Executive summary

There is much diversity in accounting for extractive industries under International Financial Reporting Standards (IFRS). Terminology is inconsistent, treatments vary and the requirements of IFRS 6: Exploration for and Evaluation of Mineral Resources permit widely divergent practices on a national and global basis. The draft discussion paper: Extractive Activities, recently released by the International Accounting Standards Board (IASB), seeks to address these concerns and harmonise the accounting between the mining and oil and gas industries.

Whilst the paper ostensibly proposes approaches producing a similar outcome to common industry practice, there are a number of interesting issues and considerations arising from it.

In summary, the draft discussion paper:

  • Proposes to adopt the oil and gas reserve definitions established by the Society of Petroleum Engineers and others.
  • Identifies the legal right to explore and extract as the fundamental basis of an oil and gas asset.
  • Recommends measurement on an historical cost basis (i.e., by capitalising exploration, evaluation and development costs) but countenances the possibility of requiring a fair value measurement basis instead.
  • Proposes to retain a modified impairment approach to assets in the exploration and evaluation stage.
  • Introduces a new asset recognition approach, which would replace the traditional full cost and successful efforts method.
  • Mandates extensive disclosures for proved, and proved and probable oil and gas reserves quantities.
  • Introduces other disclosures, including a form of standardised value for reserves and possibly responding to the Publish What You Pay proposals.

Whilst a new accounting standard may yet be some way off, the discussion paper is an important first step in a process that could radically change the shape of upstream companies' results and balance sheets, and introduce extensive new disclosure requirements for oil and gas reserves as well as enhance transparency around payments made by oil and gas companies to governments.

The IASB plans to invite comments on the project team's proposals in Q1 2010. Given the significant impact of these proposals – in particular the level of detail communicated to stakeholders, and the considerable practical burden of transitioning to, and then sustaining, the proposed reporting requirements – those who prepare financial statements would be well advised to consider these and ensure their views are heard.

Here we have summarised the draft discussion paper along with our own commentary.

Background

In August 2009, the IASB published the research project's draft findings and proposals relating to accounting for extractive industries. These proposals challenge the fundamentals of accounting for upstream activities in the oil and gas industry under IFRS.

Any new standard would replace IFRS 6 which was always intended by the IASB to be a temporary solution, and will bring an end to the flexibility the existing accounting standard affords upstream companies.

Asset measurement

A key consideration was the appropriate basis for recognising and measuring rights associated with mineral and oil and gas properties. Two measurement methods that were deliberated were fair value and historical cost.

Fair value

The draft paper sets out three possible ways for measuring fair value:

  • Market approach – using prices and other information generated in market transactions.
  • Cost approach – current replacement cost.
  • Income approach – discounted future cash flows.

Market and cost approaches were determined to be unsuitable for oil and gas properties given that each is unique; as a result an income approach was thought to be the most suitable measurement of fair value.

However, those consulted on the benefits of measuring mineral and oil and gas rights at fair value had concerns that the calculations would be costly and time consuming to prepare, whilst producing little benefit to users of financial statements given the wide range of assumptions made and the subjectivity this introduces.

In addition, measuring assets at fair value, whilst consistent with the current trend in IFRS, introduces high levels of volatility into the balance sheet and potentially the income statement.

Historical cost

The other option considered was measurement at historical cost – as is currently used in the industry to account for oil and gas assets under both the full cost and successful effort methods of accounting.

It was noted that historical cost provides a verifiable measure of the cost of acquiring, exploring and developing a property, giving an indication of management's historical performance. However, given the minimal correlation between the cost of exploration and the value of any resulting discovery, the relevance of this measure diminishes over time as subsequent exploration and evaluation generates more information about a property, and as economic conditions change. The project team's view Having considered the various options it was recommended that a single historical cost approach should be applied, and assets should be subject to depreciation and impairment testing. For the reasons set out below, this would spell the end of the longestablished accounting policy choice between the full cost and successful efforts methods. However, this is only the view of the project team, and as yet fair value accounting is not entirely off the table.

The research also concludes that historical cost measurement alone would not provide financial information that is sufficiently useful to users, and hence extensive disclosures for oil and gas reserves are also proposed, based on the reserve and resource definitions as set out in the Petroleum Resource Management System (PRMS) established by the Society of Petroleum Engineers and others.

Historical cost accounting proposals

Asset recognition

Having recommended that the most appropriate measurement basis for oil and gas assets is historical cost, the paper goes further, discussing the application of these principles in the context of the extractive process.

It acknowledges that extractive activities usually begin with the acquisition of legal rights to explore a defined area. This is followed by exploration and evaluation activities which are performed to increase the geological understanding and establish the presence (or otherwise) of oil or gas reserves in commercial quantities. Over time, this understanding will increase to a point where an assessment can be made as to whether it is economical to develop the deposit.

As a result, the view is that the underlying asset is the legal right (i.e., the licence, concession or production sharing contract (PSC)) and information associated with the oil and gas property is considered an integral part of this asset. Essentially the exploration licence, geological and geophysical studies and exploratory drilling (whether or not successful) all form part of a combined exploration and evaluation asset based on the legal rights to explore, rather than separate assets.

Whilst costs of geological and geophysical studies and exploration drilling would continue to be capitalised as enhancements to the underlying legal rights (i.e., the licence or equivalent), the proposals would lead to a change in accounting policy for any company currently applying the successful efforts method of accounting, in that unsuccessful drilling and related costs would remain capitalised as part of the oil and gas asset until and unless the legal rights are derecognised (see consideration of impairment).

Unit of account

Also addressed in the draft discussion document is the definition of a unit of account (i.e., at what level assets would be disaggregated or aggregated for recognition in the financial statements).

The paper identifies two key considerations when determining the unit of account for oil and gas assets:

  • Geographical boundaries (e.g., at the field level, individual geological area, or at a country level).
  • Components which should be recognised as a single item (e.g., the legal rights or the property, plus any associated plant and equipment assets).

The draft discussion document's view is that for exploration rights, the unit of account would initially be the legal rights held for each exploration property. As the exploration and evaluation activities occur, the unit of account would shrink such that by the time the asset is brought into development and production the geographical boundaries of each unit of account would be no larger than a single prospect, or group of contiguous prospects for which the rights are held, which is managed separately and which generates independent cash flows. Plant and machinery which is dedicated to the oil and gas property would also form part of the unit of account.

A number of practical allocation issues appear to arise in applying this concept (e.g., costs specifically related to the part of the area which is no longer of interest), which the paper does not seek to address in detail.

Depreciation

The paper proposes that existing depreciation rules under IFRS should not change. However, it does recommend that a consistent approach be applied across the extractive industries, but does not go as far as to suggest what this should be. Notably it does not address whether the unit of production calculation should be based on proved or proved plus probable reserves, and indeed questions whether it should be by reference to revenues rather than reserves. Equally it is not explicit whether depreciation on a PSC property would be based on working interest or entitlement reserves. This would imply that the existing choice between methods would end, though it does not indicate which method might ultimately prevail.

Given the North American emphasis on proved reserves, and the IASB's emphasis on best estimates, this looks set to become an area of some debate.

Impairment

IAS 36: Impairment of Assets currently applies to extractive activities in the development or production phase and the paper does not recommend any change in this approach. However, it does propose that IAS 36 would be problematic to apply to exploration properties where there is generally insufficient information available to evaluate the exploration results and reach a conclusion on whether it is economical to develop. Therefore, some modifications to the generic impairment rules would be needed.

The overall view was that exploration properties should be tested for impairment when evidence is available to suggest that full recovery of the asset is unlikely.

Therefore, exploration assets would not be tested for impairment at the reporting date if the necessary evidence was not available or inconclusive, but disclosure should be provided as to why management considers that the carrying amounts of these properties are not impaired. This represents a subtle but significant relaxation of the IAS 36 requirements, similar to that embedded in IFRS 6 at present.

The general requirements of IAS 36 should apply in determining the cash generating units for all impairment tests of oil and gas properties, including exploration and evaluation assets. This would eliminate the existing "carve out" under IFRS 6, which permits the use of pool-wide impairment tests for exploration and evaluation assets as an accounting policy choice, thus effectively bringing to an end the use of the modified full cost method of accounting presently applied by some companies under existing IFRS.

Reserves quantity and value disclosures

The paper acknowledges that the cash flows which result from the extraction of minerals or oil and gas are the most significant driver of value for upstream operations. Therefore, disclosure of information relating to quantity of reserves is important in enabling users to estimate the value of an entity's minerals or oil and gas properties and the future cash flows that might be generated from those properties.

The project team considered the variety of reserves definitions used by the oil and gas industry, including the recently updated SEC definitions. The draft discussion paper recommends adopting the reserve and resource definitions as set out in the PRMS.

Outlined opposite are the proposed disclosures. Whilst the project team acknowledges these are extensive, it nevertheless regards them as the minimum that should be provided.

Proved vs. probable

The project team proposes that entities should be required to disclose proved reserves and, separately, the sum of proved and probable reserves, both split by commodity and by country. This would represent an increase in the amount of reserve disclosure provided by many oil and gas entities. This includes all SEC registrants that until recently have been prohibited from disclosing reserve quantities other than proved reserves in their annual reports. A revised SEC rule now permits, but does not require, entities to disclose probable reserves and possible reserves.

Royalties, taxes, production sharing contracts and joint ventures

The reserves that are attributable to an entity are those quantities of oil and gas that an entity has the enforceable right to extract. In some jurisdictions, the taxation or royalty arrangements that apply to the production of minerals or oil and gas may be payable in cash or in kind (e.g., the entity may be required to deliver a portion of production quantities direct to the government or royalty owner). In principle, the project team thinks that all these arrangements should be consistently accounted for. Consequently each type of payment should be treated as an expense of the entity regardless of whether the cost is denominated in cash or in kind. As such, the financial statements should present production revenues and the tax or royalty expenses separately – and consistent with this, the underlying reserve quantities that are controlled by the entity should be included in the reserve quantities disclosed by the entity.

The paper considers specifically the disclosure issues relating to PSCs. It proposes that an entity's entitlement to reserves derived through PSCs should be included in an entity's reserves estimate. It also notes that a distinguishing feature of PSCs is that the entitlement reserves quantity increases as prices decrease (since the entity earns more units in recovering its costs), whereas in other arrangements reserves increase as prices do (as the economic viability of extracting marginal reserves improves). In view of this difference, it is proposed that entitlement reserves arising under PSCs should be disclosed separately from reserves held through other types of arrangement.

Interestingly, the proposal appears to state that the government's share of profit oil under a PSC would be excluded from reserves (and therefore presumably from revenues and expenses), whereas it also states that tax and royalty arrangements should be included in an entity's total reserves (and correspondingly in revenues when they are produced and sold), notwithstanding that these may be economically similar to profit oil. In this respect, there appears to be an anomaly in the proposals.

Reserves held by equity or cost accounted investees should not be included as part of the entity's reserve quantities (but might be separately disclosed). Therefore, the IASB's proposals to disallow proportional consolidation of joint venture entities could have significant implications for an entity's reserves quantity disclosures under the project team's proposals, because the reserves attributable to a share in a joint venture could not be attributed to the reporting entity.

Audit of reserves estimates

The paper notes that national regulators often determine whether reserves estimates must be prepared or reviewed by a "reserves auditor" or equivalent. However, it does not address the practical and capacity issues that could arise from a broader requirement for the certification or independent audit of reserves estimates.

The paper does not explicitly address whether or not the proposed disclosures would be within the scope of the audit opinion on a set of financial statements, which appears to be a natural question if the disclosures are to appear within the annual report and the requirements are to be embodied within IFRS.

Price assumptions

The paper notes that the basis to be used for selecting a commodity price assumption for estimating reserves quantities is particularly contentious, with the following alternatives being commonly proposed:

  • Market participant assumption.
  • Management's own expectations.
  • Historical price such as the year-end spot price or an average of past spot prices.

The trade off is between consistency and comparability and the relevance of the estimates on a forwardlooking basis. On balance, the project team's view is that faithful representation of reserves estimates requires the use of forecast prices, and that the use of historical prices risks misrepresenting the reserve quantities whenever the historical price is not consistent with expected future prices, particularly in the context of the often volatile commodity markets. The project team proposes that the pricing assumptions used in estimating reserve quantities should be disclosed.

Sensitivities

The project team recommends that a sensitivity analysis disclosure should be provided, to show the sensitivity of the reserves quantity estimate to changes in the main economic assumptions. They expect that, at a minimum, the sensitivity analysis would be based on changes to the price assumption. However, sometimes a reserves estimate will be more sensitive to changes in other economic assumptions (such as development, operating costs or exchange rates), in which case the sensitivity should be based on changes in those assumptions.

The project team also acknowledges that changes in the commodity price assumptions could have various impacts on the assumptions made, (e.g., about development and production costs as a result of property-specific factors, such as the optimal extraction facility design or indeed whether or not to proceed with a development at all).

The paper recommends that the sensitivity analysis should take into account the impact of changes an entity should be able to reasonably anticipate and quantify, without requiring a detailed reassessment of all components of the reserves estimate. It seems likely that this could give rise to significant issues in practice, for example where a particular development is highly material to an entity's reserves.

Value disclosures

On the premise that assets would be recognised at historic cost, the paper recommends standardised value disclosures in addition to volumetric disclosures. The rationale is that users familiar with the disclosure of the standardised measure have indicated that it can provide useful information, notwithstanding that the value itself may not be useful.

This approach is similar to that already mandated in the US, except that the project team recommends the disclosures be applied to proved plus probable reserves, rather than just proved reserves.

Publish What You Pay Proposals

Also included in the paper is a chapter addressing the Publish What You Pay Proposals, which are being promoted by a coalition of non-governmental organisations. The disclosures proposed overlap to a large extent with those outlined in the draft discussion paper, with the exception of payments to governments. There is no recommendation as to whether such disclosures should be included in financial reports or not, although it does outline the view that disclosure of payments to governments would be useful to some capital providers, but may be difficult or costly to prepare for some entities, and could be commercially or contractually sensitive in some circumstances.

Closing remarks

History has shown that views expressed early in the life of an IASB project are the most influential, before a momentum builds towards a particular outcome.

This is particularly so in this case, because the unusual circumstances surrounding the draft discussion paper mean the IASB has not yet formulated its own views and may decide to propose a different approach (e.g., the use of fair value accounting for oil and gas properties).

Given the significant impact of the proposals – in particular the level of detail that will need to be communicated to stakeholders and the considerable practical burden of transitioning to, and then sustaining, the proposed reporting requirements – those who prepare financial statements would be well advised to consider the proposals and ensure their views are heard.

The content of this article is intended to provide a general guide to the subject matter. Specialist advice should be sought about your specific circumstances.