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Oil & Gas Spotlight — Fueling discussion about the FASB’s new revenue recognition standard

Published on: Oct 23, 2014

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The Bottom Line

  • On May 28, 2014, the FASB and IASB issued their final standard on revenue from contracts with customers. The standard, issued as ASU 2014-091 by the FASB and as IFRS 152 by the IASB, outlines a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance,3 including industry-specific guidance such as that for oil and gas (O&G) entities in ASC 932-605.4
  • The new revenue model is not expected to result in significant changes in revenue recognition for many of the commodity sales transactions in the O&G sector.
  • O&G entities will, however, need to consider how the new standard might affect their accounting for certain arrangements, including, but not limited to, (1) commodity exchange arrangements, (2) production imbalances, (3) blend-and-extend (B&E) contract modifications, (4) take-or-pay arrangements, (5) sales of mineral interests and production payments, (6) drilling contracts, and (7) contracts with volumetric optionality, variable consideration, or royalty payments.
  • ASU 2014-09 is effective for annual reporting periods beginning after December 15, 2016, for public entities (including interim periods therein). Entities have the option of using either a full retrospective or a modified approach to adopt the guidance in the ASU.
  • The ASU requires considerably more extensive disclosures than current revenue standards. Therefore, O&G entities may need to modify their systems and processes to gather information about contracts with customers that is not otherwise readily available.

Beyond the Bottom Line

This Oil & Gas Spotlight discusses the new revenue model and highlights key accounting issues and potential challenges for O&G entities that recognize revenue under U.S. GAAP or IFRSs. For additional information about the new standard, see Deloitte’s May 28, 2014, Heads Up.

Background

The goals of the ASU are to clarify and converge the revenue recognition principles under U.S. GAAP and IFRSs while (1) streamlining, and removing inconsistencies from, revenue recognition requirements; (2) providing “a more robust framework for addressing revenue issues”; (3) making revenue recognition practices more comparable; and (4) increasing the usefulness of disclosures. The ASU states that the core principle for revenue recognition is that an “entity shall recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services.”

The ASU indicates that an entity should perform the following five steps in recognizing revenue:

  • “Identify the contract(s) with a customer” (step 1).
  • “Identify the performance obligations in the contract” (step 2).
  • “Determine the transaction price” (step 3).
  • “Allocate the transaction price to the performance obligations in the contract” (step 4).
  • “Recognize revenue when (or as) the entity satisfies a performance obligation” (step 5).

As a result of the ASU, entities will need to comprehensively reassess their current revenue accounting and determine whether changes are necessary. Entities are also required to provide significantly expanded disclosures about revenue recognition, including both quantitative and qualitative information about (1) the amount, timing, and uncertainty of revenue (and related cash flows) from contracts with customers; (2) the judgment, and changes in judgment, used in applying the revenue model; and (3) the assets recognized from costs to obtain or fulfill a contract with a customer.

Key Accounting Issues

Although the ASU may not significantly change how O&G entities typically recognize revenue, a number of the ASU’s requirements may be inconsistent with current practice. Discussed below are some key provisions of the ASU that may affect O&G entities.

Thinking It Through

To help O&G entities implement the ASU, the FASB and IASB have created a joint transition resource group and the AICPA has assembled an O&G industry task force.5 In addition, the AICPA is currently developing an accounting guide on revenue recognition.

Commodity Exchange Arrangements

Scope Considerations

Commodity exchange arrangements are common in the O&G industry. In these arrangements, an entity agrees to sell a certain quantity and grade of a commodity to a counterparty at a specified location and simultaneously agrees to buy a specific quantity and grade of a similar commodity from that same counterparty at another location. In effect, specified inventories of the two parties are exchanged (e.g., in-ground natural gas liquids are exchanged at different storage hubs). Entities usually enter into commodity exchange arrangements to meet the operational needs of the business without incurring any ancillary costs (e.g., transportation costs).

Generally, the purpose of exchange arrangements is to allow the parties to meet the needs of the market; therefore, the parties are not considered to be the end-user purchasers of the product if they are in the same line of business. Although a counterparty in a commodity exchange arrangement may meet the ASU’s definition of a “customer,” nonmonetary exchanges between two parties in the “same line of business” are outside the new standard’s scope and would be accounted for in accordance with ASC 845. Therefore, the new revenue model is not expected to have a significant impact on commodity exchange arrangements if they are currently accounted for as like-kind exchanges.

Thinking It Through

In certain arrangements, a marketer may agree to sell crude oil or gas to a refiner or gas processor and simultaneously buy back separate, refined products such as condensates or natural gas liquids. O&G entities should be aware that although such agreements may be structured similarly to the commodity exchange arrangements discussed above, the applicability of the ASU to the two types of arrangements may differ. For example, O&G entities may need to assess whether the refining or processing counterparty meets the definition of a customer in the ASU or should be accounted for under other GAAP.

Production Imbalances

Production imbalances in a well arise when working interest owners in a production-sharing arrangement sell more (“overlift”) commodity production in a given period than they are entitled to sell according to their working interest ownership percentages. The overlift party thus has an obligation to settle the imbalance with the underlift party financially or in kind by the end of the property’s life.

Current guidance in ASC 932-10-S99-5 generally permits owners to record revenue related to a production-sharing arrangement by using either the entitlements method or the sales method. Under the entitlements method, an owner generally records revenue equivalent to its share of production and a payable (overlift) or receivable (underlift) for the difference between volumes it actually sold to third parties and its working interest. Under the sales method, an owner generally records revenue for the actual amount of the production sold to third parties and adjusts reserves for any shortfall.

Identifying the Contract With the Customer

If the sales contract with the third party is considered a contract with a customer,6 revenue on those sales would be recognized in accordance with the new model. Further, while the SEC staff’s accounting guidance on the sales and entitlements methods (ASC 932-10-S99-5) remains in effect, it does not preclude the underlift party from accounting for the production imbalance under the new revenue model if the overlift party meets the definition of a customer in the ASU.

O&G entities should consider whether an underlift party’s production imbalance with an overlift party constitutes a contract with a customer that should be accounted for under ASU 2014-09 or whether the SEC industry guidance in ASC 932-10-S99-5 would be more applicable. If an O&G entity determines that a production imbalance should be accounted for under the ASU, it should consider the potential applicability of the considerations discussed below, including volumetric optionality (see Volumetric Optionality below).

Thinking It Through

The ASU does not amend the SEC’s guidance in ASC 932-10-S99-5, which states that both the sales and entitlements methods of accounting for production imbalances are acceptable. However, because the SEC has indicated its intention to review the revenue recognition guidance in SAB topics, O&G entities should continue to monitor this guidance for any potential changes.

Blend-and-Extend Contract Modifications

Contract Modifications

O&G entities should consider how they are affected by the ASU’s guidance on accounting for “approved” modifications to contracts with customers. The approval of a contract modification can be in writing, by oral agreement, or implied by customary business practices, and a contract modification is considered approved when it creates new, or changes existing, enforceable rights or obligations. A contract modification must be accounted for as a separate contract when (1) it results in a change in contract scope because of additional promised “distinct” goods or services (see Distinct Performance Obligations below) and (2) the additional consideration reflects the entity’s stand-alone selling price for those additional promised goods or services (including any appropriate adjustments to reflect the circumstances of the contract). That is, the entity would continue to account for the existing contract as if it was not modified and would account for the additional goods or services under the modification as a “new” contract.

If a contract modification is not considered a separate contract (i.e., it does not meet the criteria above), the entity should evaluate the remaining goods and services in the modified contract and determine whether to account for the modification prospectively (if the remaining goods and services are distinct from those already transferred) or retrospectively in accordance with the ASU. If the remaining goods and services are distinct from those already transferred, the modification is accounted for prospectively, the transaction price is updated (i.e., it now includes both the remaining consideration from the original contract and the additional consideration in the modification), and the updated transaction price is allocated to the remaining goods and services to be transferred. In contrast, if the goods or services are not distinct and are part of a single performance obligation, the modification is treated retrospectively and the amount of revenue recognized is adjusted to reflect the new modified contract (e.g., the measure of progress is adjusted to account for the new expectation of performance completed), resulting in a cumulative-effect catch-up adjustment.

B&E contract modifications are common in the O&G industry. In a typical B&E modification, the supplier and customer may renegotiate the contract to allow the customer to take advantage of lower commodity pricing while the supplier increases its future delivery portfolio. Under such circumstances, the customer and supplier agree to “blend” the remaining, original, higher contract rate with the lower, extension-period rate for the remainder of the original contract term plus an extended term. The supplier therefore defers the cash realization of some of the contract fair value that it would have received under the original contract terms until the extension period, at which time it will receive an amount that is greater than the current market price for those periods as of the date of the modification.

Potential Impact of New Revenue Model

O&G entities should carefully evaluate the facts and circumstances related to a B&E contract modification to determine whether it should be accounted for as a new contract (which may include a significant financing component) or as a prospective contract modification. A B&E contract modification is treated as a new contract when distinct goods or services are added to the contract and the additional consideration reflects the stand-alone selling price of those additional goods or services. In such cases, the payment terms may need to be reevaluated because the payment of consideration may create a significant financing component in which some of the consideration for the future goods or services is paid early as a result of the “blended” price agreed to by the parties. In contrast, when the additional distinct goods are not included at the stand-alone selling price in the contract modification, the modification will be treated prospectively (since the remaining and additional deliveries would be distinct from the goods delivered as of the modification date) and the new blended price will be allocated to the remaining goods to be provided to the customer (including the undelivered goods in the original contract and the newly added goods).

Example

Entity A enters into a four-year arrangement to sell West Texas Intermediate (WTI) crude oil to Customer B at a fixed price of $105 per barrel (BBL). By the end of year 2, the price of WTI has dropped significantly and Customer B wishes to renegotiate the contract to take advantage of lower spot prices at $95/BBL. Entity A and Customer B agree to extend the terms of the existing contract by two years (i.e., there are four remaining years after modification); the new contract has a fixed-price structure of $100/BBL.

Thus, Entity A will be receiving $100/BBL ($5/BBL less than originally contracted) during years 3 and 4. In contrast, during years 5 and 6 (i.e., the extension period), Entity A will be receiving $5/BBL more than the market price of $95/BBL.

Potential Alternatives

If the modified price is determined to be the stand-alone selling price for the additional WTI provided in years 5 and 6 (e.g., volumes are expected to be consistent in years 3
through 6 and the $95/BBL is determined to be the stand-alone selling price of the additional WTI in years 5 and 6), the contract modification should be treated as a new contract. However, the payment terms do not align with this “new” contract because payments will be received in years 5 and 6 at the blended rate of $100/BBL. Entity A should therefore consider whether a significant financing component has been created in the new contract, since the payments made in years 5 and 6 under the new contract are higher than the stand-alone selling price (i.e., Customer B is paying Entity A back for its financing in years 3 and 4) while the payments in years 3 and 4 are lower than those under the original contract because of the blended rate that Entity A and Customer B agreed to as part of the contract modification.

If the modified price for the additional WTI in years 5 and 6 is not determined to be the stand-alone selling price and the WTI delivered in years 3 through 6 (i.e., the remaining undelivered goods as of the contract modification) is assessed and determined to be “distinct” from the deliveries of WTI in years 1 and 2, the contract modification is not treated as a new contract but as a prospective modification and the blended rate of $100/BBL is recognized for crude delivered throughout the remaining contract (years 3 to 6). In such circumstances, an entity would generally conclude that no financing is present.

Distinct Performance Obligations

Identifying the Performance Obligations in the Contract

The ASU provides guidance on evaluating the promised “goods or services”7 in a contract to determine each performance obligation (i.e., the unit of account). A performance obligation is each promise to transfer either of the following to a customer:

  • “A good or service (or a bundle of goods or services) that is distinct.”
  • “A series of distinct goods or services that are substantially the same and that have the same pattern of transfer to the customer.”

A series of distinct goods or services has the same pattern of transfer if both of the following criteria are met: (1) each distinct good or service in the series meets the criteria for recognition over time and (2) the same measure of progress is used to depict performance in the contract. Therefore, a simple forward sale of crude oil for which delivery of the same product is required over time would be treated as a single performance obligation satisfied continuously throughout the contract if it meets the above criteria. In this case, the entity would determine an appropriate method for measuring progress toward complete satisfaction of the single performance obligation (i.e., the transfer of control of the promised goods over time) and would recognize the transaction price as revenue as progress is made.

Variable Pricing

Determining the Transaction Price

The use of variable consideration (e.g., formula-based pricing) may present challenges related to estimating and allocating the transaction price and applying the ASU’s constraint guidance. When the transaction price includes a variable amount, an entity must estimate the variable consideration by using either an “expected value” (probability-weighted) approach or a “most likely amount” approach, whichever is more predictive of the amount to which the entity will be entitled.

An estimate of variable consideration is only included in the transaction price to the extent that it is probable8 that subsequent changes in the estimate would not result in a “significant reversal” (this concept is commonly referred to as the “constraint”). The ASU requires entities to perform a qualitative assessment that takes into account the likelihood and magnitude of a potential revenue reversal and provides factors that could indicate that an estimate of variable consideration is subject to significant reversal (e.g., susceptibility to factors outside the entity’s influence, long period before uncertainty is resolved, limited experience with similar types of contracts, practices of providing concessions, or a broad range of possible consideration amounts). This estimate would be updated in each reporting period to reflect changes in facts and circumstances. In addition, the constraint does not apply to sales- or usage-based royalties derived from the licensing of intellectual property; rather, consideration from such royalties is only recognized as revenue at the later of when the performance obligation is satisfied or when the uncertainty is resolved (e.g., when subsequent sales or usage occurs).

Thinking It Through

Under current U.S. GAAP, the amount of revenue recognized is generally limited to the amount that is not contingent on a future event (i.e., the price is fixed or determinable). Under the ASU, an entity must include some or all of an estimate of variable (or contingent) consideration in the transaction price (which is the amount to be allocated to each unit of account and recognized as revenue) when the entity concludes that it is probable that changes in its estimate of such consideration will not result in significant reversals of revenue in subsequent periods. The guidance in the ASU, which is generally less restrictive, is likely to result in earlier revenue recognition than the guidance in current U.S. GAAP. To comply with the ASU’s requirements for estimating the transaction price and determining what amount, if any, is subject to potential reversal (and should be excluded from the transaction price), management may need to use significant judgment, particularly since the transaction price must be updated in each reporting period.

Significant Financing Component

Determining the Transaction Price

Adjustments for the time value of money are required if the contract includes a “significant financing component” (as defined in the ASU). Generally, no adjustment is necessary if payment is expected to be received within one year of the transfer of goods or services to the customer. However, if an entity concludes, on the basis of the payment terms, that there is a significant financing component, it should adjust the sales price when recording revenue to present the amount that would have been attained had the buyer paid cash for the goods or services on the date of sale.

Thinking It Through

Payment terms in the O&G industry often include up-front fees or extended payment terms (e.g., long-term volumetric production payments). Under current guidance, arrangements that offer extended payment terms often result in the deferral of revenue recognition since the fees are typically not considered fixed or determinable unless the entity has a history of collecting fees under such payment terms without providing any concessions. In the absence of such a history, revenue is recognized when payments become due or when cash is received from the customer, whichever is earlier. Typically, under today’s accounting, there would be no adjustment for advanced payments.

Under the ASU, if the financing term extends beyond one year and a significant financing component is identified, the entity would need to initially estimate the transaction price by incorporating the impact of any potential price concessions (see discussion above in Variable Pricing) and then adjust this amount to account for the time value of money. That amount adjusted for any concessions and the time value of money would then be recognized as revenue when the entity transfers control of the good or service to the customer. When the entity is providing financing, interest income would be recognized as the discount on the receivable unwinds over the payment period. However, when the entity receives an up-front fee, the entity is deemed to be receiving financing from the customer and interest expense is recognized, with a corresponding increase to revenue recognized. This recognition pattern may differ significantly from the pattern under current U.S. GAAP, as described above.

Take-or-Pay Arrangements

In a take-or-pay arrangement, a customer pays a specified price to a supplier for a minimum volume of product or level of services. Such an arrangement is referred to as “take-or-pay” because the customer must pay for the product or services regardless of whether it actually takes delivery. Natural gas and other commodity off-take contracts are commonly structured as take-or-pay. Service arrangements, such as those for natural gas storage or transportation, can also be structured as take-or-pay.

Identifying the Performance Obligations in the Contract

Under the ASU, a supplier in a take-or-pay arrangement would generally conclude that it has entered into a contract with a customer to deliver a series of distinct, but substantially the same, goods consecutively over time (see discussion above in Distinct Performance Obligations). Therefore, the supplier should account for that series of distinct goods as a single performance obligation — and as a single unit of account — when both of the following two criteria are met:

  • The customer simultaneously receives and consumes the benefits of each distinct delivery of natural gas or other commodity (i.e., the delivery of natural gas meets the criterion in ASC 606-10-25-27(a) and, as a result, the series meets the criterion in ASC 606-10-25-15(a)).
  • The same measure of progress for each distinct delivery of natural gas or other commodity (e.g., a time- or unit-based measure) would be used, thereby satisfying the criterion in ASC 606-10-25-15(b).

Recognizing Revenue When (or as) Performance Obligations Are Satisfied

Because the performance obligation in a take-or-pay arrangement is satisfied over time, the supplier recognizes revenue by measuring progress toward satisfying the performance obligation in a manner that best depicts the transfer of goods or services to the customer. The best depiction of the supplier’s performance in transferring control of the goods and satisfying its performance obligation may differ depending on the terms of the take-or-pay arrangement:

  • Consider a vanilla take-or-pay arrangement involving monthly deliveries of natural gas in which the customer pays irrespective of whether it takes delivery and cannot make up deliveries not taken. In this case, it may be appropriate for the supplier to use an output measure of progress based on time to recognize revenue because the performance obligation is satisfied as each month passes.
  • In a take-or-pay arrangement involving monthly deliveries of natural gas in which the customer can make up deliveries not taken later in the contract tenor, an output measure of progress based on units delivered may be appropriate. In this case, the supplier should recognize revenue for volumes of natural gas actually delivered to the customer each month and recognize a contract liability for volumes not taken, since the supplier’s performance obligation related to those volumes is unsatisfied despite receipt of customer payment. That is, the supplier would need to provide more gas in the future months to complete its promise to the customer.

Thinking It Through

Although ASU 2014-09 will supersede the industry guidance in ASC 932-605-25-2 on take-or-pay arrangements, we expect that the accounting for such arrangements will largely remain the same in practice.

Volumetric Optionality

Material Options

The ASU contains implementation guidance on recognizing revenue related to options for additional goods or services (i.e., written volumetric optionality). Upstream and marketing companies should carefully consider any additional quantities that the customer has rights to in take-or-pay or other off-take arrangements and whether such volumetric optionality represents a separate performance obligation in the contract. If a right to additional quantities results in a material right that the customer would not otherwise receive had it not entered into that contract, the option is considered a separate performance obligation. For example, a material right may be identified for additional quantities at prices that are significantly in-the-money (as determined at contract inception).

The consideration in a contract that includes options for additional goods or services may include an up-front payment. For example, that payment may reflect the present value of the difference between a fixed price for optional quantities and consideration determined by using the supplier’s forward commodity price curve. When that is the case, the up-front payment is included in the overall transaction price, which would be allocated by applying the ASU’s allocation method to the performance obligations identified (which may include a separate performance obligation for a material right). In addition, the entity should evaluate whether a significant financing component is present (see Significant Financing Component above).

Drilling Contracts

Whether for developing properties offshore or on land, drilling contracts are often complex, involving significant amounts of consideration and including specialized assets and service offerings in various forms (e.g., day-rate, turnkey). Drilling contractors will need to carefully evaluate whether their contracts are — or contain — leases within the scope of ASC 840.9 If a contract (or part of a contract) is within the scope of ASC 606, the contractor should perform the steps discussed below under the new revenue model.

Identifying the Performance Obligations in the Contract

Drilling contracts often contain “mobilization” or “localization” terms under which the drilling contractor is to move an agreed-upon drilling rig and equipment from a current location to the drilling site (or sites). For example, in offshore, day-rate drilling contracts, there is often an explicit day rate for mobilization work and periods. This day rate is generally lower than the day rate for the actual drilling period and corresponding activities.

Contractors should carefully examine whether an activity in a drilling contract is a promise to transfer a good or service to a customer (i.e., a performance obligation). ASC 606-10-25-17 states the following regarding identifying a performance obligation in a contract:

Performance obligations do not include activities that an entity must undertake to fulfill a contract unless those activities transfer a good or service to a customer. For example, a services provider may need to perform various administrative tasks to set up a contract. The performance of those tasks does not transfer a service to the customer as the tasks are performed. Therefore, those setup activities are not a performance obligation.

That is, a drilling contractor must first consider whether an activity such as mobilization is necessary to fulfill the larger drilling contract (i.e., a set-up activity) and is not a promise to deliver a service. A drilling contractor may conclude that such an activity does not constitute delivery of a service to the well operator (i.e., the customer). In this instance, the costs incurred to set up the drilling service (i.e., the mobilization activities) may be capitalized as an asset in accordance with the new contract cost provisions in ASC 340-40 if the criteria are met and the drilling contractor would not begin fulfillment of the contract with the well operator until the drilling activity commences. Also, any payments received during the mobilization activity would be recognized as a contract liability (deferred revenue) and only recognized when the contractor satisfies its obligations (i.e., performs the drilling service) for its customer (the well operator).

However, if an activity such as mobilization is a promise to deliver a service to the operator, a contractor must consider whether it is distinct and meets both criteria in ASC 606-10-25-19 for separate revenue recognition:

  • The “service is capable of being distinct” (i.e., the operator can benefit from the service on its own or together with other resources that are readily available).
  • The “service is distinct within the context of the contract” (i.e., the promise to deliver the service “is separately identifiable from other promises in the contract”).

In this instance, the drilling operator begins fulfilling its promise (or promises) to the customer upon the start of the mobilization efforts and therefore would begin to recognize revenue when mobilization begins (rather than when drilling begins) when such efforts are deemed “an activity” and not a performance obligation, regardless of whether the contract contains one or more distinct services.

Thinking It Through

A drilling contractor should carefully consider whether the efforts involved in the mobilization represent an activity (i.e., a set-up activity) or a service that provides a benefit to the customer. If the mobilization efforts satisfy a promise to the customer by delivering a service, the drilling contractor must determine whether that mobilization service is separable from the drilling service. In many cases, the drilling contractor will conclude that mobilization of a drilling rig does not result in a separate benefit for well operators and that the activity is thus incapable of being distinct. However, in situations in which that conclusion is inappropriate, contractors will need to determine whether mobilization is (1) both separately identifiable in the contract and distinct in the context of the contract, and thus a distinct performance obligation, or (2) a single service delivery in combination with the drilling operations.

Recognize Revenue When (or as) Performance Obligations Are Satisfied

Under the ASU, a drilling contractor is likely to conclude that its performance obligation for drilling services in a day-rate or other drilling contract is satisfied over time because the contractor’s performance creates or enhances an asset (e.g., the oil well) that the customer controls as the asset is created or enhanced. That is, such a performance obligation would meet one of the criteria in ASC 606-10-25-27 to be satisfied over time. Therefore, in such cases, a drilling contractor would recognize revenue by measuring progress toward satisfying the performance obligation in a manner that best depicts the transfer of goods or services to the customer.

Certain types of fixed pricing provisions in a drilling contract may warrant a careful examination of the measure of progress to be used. Consider a two-year offshore drilling contract whose initial day rate of $500,000 increases by a fixed increment of $50,000 in each semiannual period. In contemplating the appropriate measure of progress that best depicts the transfer of its service, the contractor in this example may consider the following:

  • Output measure of progress (e.g., time, days drilled) — As it performs, the contractor could potentially recognize an amount of revenue equivalent to the total transaction price (determined under step 3 of the new revenue model) divided by the total number of days over which services are expected to be delivered. Days during which mobilization and other activities are to be performed may be included in that calculation depending on the conclusions the contractor reaches when identifying the contract’s performance obligations. A fixed day rate that increases twice per year by a fixed amount of $50,000 could be factored into the calculation of the total transaction price and recognized on a straight-line basis10 over the tenor of the contract (i.e., at an equal amount for each day of contract delivery).
  • Input measure of progress (e.g., costs incurred) — The contractor may recognize as revenue a percentage of the total transaction price, calculated as a ratio of the costs of drilling for the period (e.g., labor and fuel costs) to the total costs to be incurred to deliver the contract. Again, fixed pricing that increases semiannually by a fixed day rate of $50,000 could be factored into the calculation of the total transaction price. Revenue could be recognized, for example, in increasing amounts over the tenor of the contract if costs are expected to rise as the contract is delivered. This method would be affected by whether the contractor concludes that the mobilization efforts represent an activity or a performance obligation. If the efforts represent an activity, the costs would be considered set-up costs and, if they meet certain criteria, would be capitalized as an asset and then systematically amortized during the drilling service. If the mobilization efforts represent a service (a performance obligation), then the costs incurred would be included within the cost-to-cost measure of progress.

Royalty Payments

O&G entities often enter into royalty arrangements with the owners of mineral rights, which can be either private or governmental entities. Under current practice, an O&G entity extracts the commodity and remits a royalty payment to the mineral rights owner upon (1) the completion of the extraction activities or (2) the sale of the oil or gas. The nature and extent of the mineral owners’ involvement, as well as the contractual structure of these types of arrangements, may vary. For instance, some arrangements may result in the mineral rights owner‘s active involvement in the production process, which may serve as a catalyst to both the lifting arrangement with the O&G entity and the sales arrangement with a third party; however, other arrangements may leave the uplifting and subsequent sales arrangements to the O&G entity. In addition, some arrangements may be based on a specified volume of oil or gas extracted at a predetermined rate, while other arrangements may require the entity to sell all of the extracted commodity to a third party and pay the mineral rights owner a proportion of aggregate transaction proceeds less certain lifting costs.11

Under the ASU, an O&G entity should first consider whether the contract with royalty payments is within the scope of ASC 606; that is, whether the counterparty is a customer rather than a collaborator and therefore within the scope of ASC 606. If so, the entity would determine the amount of consideration it expects to be entitled to, which would exclude amounts collected on behalf of third parties. Therefore, if the entity is solely collecting amounts on a third party’s behalf (e.g., the government), then such amounts would not be included in the transaction price since they are effectively passed through the entity to the government. In addition, the entity should consider the ASU’s implementation guidance on principal-versus-agent considerations (see Principal-Versus-Agent Considerations below) to determine whether its promise in the contract is to provide the extraction service (gross presentation) or to arrange for another party (acting as an agent) to transfer goods or services (net revenue recognition).

Collaborative Arrangements

O&G entities should assess their royalty arrangements with mineral rights owners to determine whether the arrangements are contracts with a customer or whether they are sharing in the risks and benefits under a collaborative arrangement. The ASU broadly applies to contracts with customers and defines a customer as “a party that has contracted with an entity to obtain goods or services that are an output of the entity’s ordinary activities in exchange for consideration.” The ASU notes:

A counterparty to the contract would not be a customer if, for example, the counterparty has contracted with the entity to participate in an activity or process in which the parties to the contract share in the risks and benefits that result from the activity or process (such as developing an asset in a collaboration arrangement) rather than to obtain the output of the entity’s ordinary activities.

In an arrangement that results in the mineral rights owner’s active involvement in the production process (i.e., its input in the lifting process or involvement in executing the sales arrangement with a third party), the O&G entity might conclude that it is more of a collaborative arrangement and therefore outside the ASU’s scope.

Principal-Versus-Agent Considerations

Other parties may be involved in providing goods or services to an entity’s customers. In such cases, the entity must determine whether “the nature of its promise is a performance obligation to provide the specified goods or services itself (that is, the entity is a principal) or to arrange for the other party to provide those goods or services (that is, the entity is an agent).” An entity is a principal when it controls a promised good or service before the entity transfers the good or service to the customer. The ASU provides indicators and other implementation guidance to help an entity determine whether the entity is acting as a principal (revenue is recognized on a gross basis) or as an agent (revenue is recognized on a net basis).

In a principal-versus-agent determination, an O&G entity must assess the nature and terms of the arrangement. For example, it would need to determine whether its involvement in the lifting activities and subsequent delivery to a third party constitutes the fulfillment of the entity’s own performance obligation to deliver goods to the customer (i.e., serving as a principal) or whether the goods are being delivered on behalf of the mineral owner (i.e., the entity is acting as an agent). This conclusion will directly affect whether revenue should be recorded gross or net (i.e., whether solely the royalty payment should be recognized as revenue).

Sales of Mineral Interests and Production Payments

ASU 2014-09 governs the amount, timing, and recognition of gains and losses from the sale of fixed assets and real property. (See Deloitte’s July 2, 2014, Heads Up for additional considerations related to the accounting for real estate sales under the new revenue standard.) However, conveyances of mineral interests and O&G properties are outside the ASU’s scope. Therefore, the industry guidance in ASC 932-360 remains in effect and, for example, an O&G entity’s sale and retention of its operating and nonoperating interests in a well, respectively, would continue to be accounted for under ASC 932. However, that same entity’s sale of its drilling equipment on the property would be accounted for in accordance with the ASU.

The ASU is also not expected to have a significant impact on production payments. Under ASC 932, a production payment repayable in cash plus interest out of proceeds from a specific mineral interest is considered to be a financing and not a sale of that mineral interest. However, a volumetric production payment (VPP) that is repaid in a specified amount of commodity lifted from a specific mineral interest and delivered free and clear of all expense associated with that interest’s operation reflects a sale of that mineral interest. Currently, ASC 932-360 requires the seller in a VPP to record deferred revenue that is recognized as the commodity is delivered. This guidance is also outside the ASU’s scope. Therefore, the accounting for VPPs is not expected to change as a result of the new revenue model.

Disclosures

The ASU requires entities to disclose both quantitative and qualitative information that enables “users of financial statements to understand the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers.” The ASU’s disclosure requirements, which are significantly more comprehensive than those in existing revenue standards, include the following (with certain exceptions for nonpublic entities):

  • Presentation or disclosure of revenue and any impairment losses recognized separately from other sources of revenue or impairment losses from other contracts.
  • A disaggregation of revenue to “depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors” (the ASU also provides implementation guidance).
  • Information about (1) contract assets and liabilities (including changes in those balances), (2) the amount of revenue recognized in the current period that was previously recognized as a contract liability, and (3) the amount of revenue recognized in the current period that is related to performance obligations satisfied in prior periods.
  • Information about performance obligations (e.g., types of goods or services, significant payment terms, typical timing of satisfying obligations, and other provisions).
  • Information about an entity’s transaction price allocated to the remaining performance obligations, including (in certain circumstances) the “aggregate amount of the transaction price allocated to the performance obligations that are unsatisfied (or partially unsatisfied)” and when the entity expects to recognize that amount as revenue.
  • A description of the significant judgments, and changes in those judgments, that affect the amount and timing of revenue recognition (including information about the timing of satisfaction of performance obligations, the determination of the transaction price, and the allocation of the transaction price to performance obligations).
  • Information about an entity’s accounting for costs to obtain or fulfill a contract (including account balances and amortization methods).
  • Information about the policy decisions (i.e., whether the entity used the practical expedients for significant financing components and contract costs allowed by the ASU).

The ASU requires entities, on an interim basis, to disclose information required under ASC 270 as well as to provide annual disclosures (described above) about (1) the disaggregation of revenue, (2) contract asset and liability balances and significant changes in those balances since the previous period-end, and (3) the transaction price allocated to the remaining performance obligations.

Nonpublic entities can use certain practical expedients under the ASU to avoid providing some of the disclosures required of public entities. For additional information about the disclosure relief provided, see the appendix below.

Effective Date and Transition

The ASU is effective for annual reporting periods (including interim reporting periods within those periods) beginning after December 15, 2016, for public entities. Early application is not permitted (however, early adoption is optional for entities reporting under IFRSs).

The effective date for nonpublic entities is annual reporting periods beginning after December 15, 2017, and interim reporting periods within annual reporting periods beginning after December 15, 2018. Nonpublic entities may also elect to apply the ASU as of any of the following:

  • The same effective date as that for public entities (annual reporting periods beginning after December 15, 2016, including interim periods).
  • Annual periods beginning after December 15, 2016 (excluding interim reporting periods).
  • Annual periods beginning after December 15, 2017 (including interim reporting periods).

Entities have the option of using either a full retrospective or a modified approach to adopt the guidance in the ASU.

  • Full retrospective application — Retrospective application would take into account the requirements in ASC 250 (with certain practical expedients). Under this approach, entities would need to reevaluate their contracts from inception to determine the income recognition pattern that best depicts the transfer of goods and services. Further, for comparative financial statement purposes, public entities with a calendar year-end would be required to present income under the new revenue model beginning on January 1, 2015.
  • Modified retrospective application— Under the modified approach, an entity recognizes “the cumulative effect of initially applying [the ASU] as an adjustment to the opening balance of retained earnings . . . of the annual reporting period that includes the date of initial application” (revenue in periods presented in the financial statements before that date is reported under guidance in effect before the change). Under the modified approach, the guidance in the ASU is only applied to existing contracts (those for which the entity has remaining performance obligations) as of, and new contracts after, the date of initial application. The ASU is not applied to contracts that were completed before the effective date (i.e., an entity has no remaining performance obligations to fulfill). Entities that elect the modified approach must disclose an explanation of the impact of adopting the ASU, including the financial statement line items and respective amounts directly affected by the standard’s application. The following chart illustrates the application of the ASU and legacy GAAP under the modified approach:

Oil and gas spotlight - Revenue -1

 

Thinking It Through

The modified transition approach provides entities relief from having to restate and present comparable prior-year financial statement information; however, entities will still need to evaluate existing contracts as of the date of initial adoption under the ASU to determine whether a cumulative adjustment is necessary. Therefore, entities may want to begin considering the typical nature and duration of their contracts to understand the impact of applying the ASU and determine the transition approach that is practical to apply and most beneficial to financial statement users.

Implementation Challenges for Oil and Gas Entities

Increased Use of Judgment

Management will need to exercise significant judgment in applying certain aspects of the ASU’s requirements, including those related to the identification of performance obligations, determination of the transaction price, and allocation of revenue to each performance obligation. It is important for O&G entities to consider how the ASU specifically applies to them so that they can prepare for any changes in revenue recognition patterns.

Retrospective Application

The ASU allows retrospective application, with certain optional practical expedients available to entities at their discretion. This aspect of the ASU may require O&G entities to gather data and assess contracts that commenced several years before the ASU’s effective date. O&G entities also will most likely be required to perform dual tracking of revenue balances during this retrospective period, given the potential difficulty associated with retroactively recalculating revenue balances at the time the ASU becomes effective.

Systems, Processes, and Controls

The ASU requires several new practices and disclosure requirements under which O&G entities will have to gather and track information that they may not have previously monitored. The systems and processes associated with such information may need to be modified to support the capture of additional data elements that may not currently be supported by legacy systems.

O&G entities with large volumes of sales deals may find it operationally challenging to assess each sales deal to categorize and account for customer incentives in accordance with the ASU; such entities may need to make substantial system modifications to facilitate this process.

O&G entities may also recognize an asset for certain costs of obtaining or fulfilling a contract (unless the amortization period is one year or less and entities choose to recognize those costs as expenses immediately). O&G entities may need to modify their current accounting practices and make appropriate system modifications to track data on contract duration, contract costs, and periodic amortization and impairment testing of capitalized costs.

Further, to ensure the effectiveness of internal controls over financial reporting, management will need to assess whether additional controls need to be implemented. O&G entities may also need to begin aggregating essential data from new and existing contracts since many of these contracts will most likely be subject to the ASU.

Thinking It Through

Note that the above are only a few examples of possible changes O&G entities may need to make to their systems, processes, and controls. O&G entities should evaluate all aspects of the ASU’s requirements to determine whether any other modifications may be necessary.

Income Taxes

Federal income tax law provides both general and specific rules for recognizing revenue on certain types of transactions (e.g., long-term contracts and arrangements that include advance payments for goods and services). These rules are often consistent with the method a taxpayer uses for financial reporting purposes and, if so, the taxpayer applies the revenue recognition method it uses in maintaining its books and records (e.g., cash basis, U.S. GAAP, IFRSs). Although the Internal Revenue Code does not require entities to use any particular underlying financial accounting method to determine their taxable income (such as U.S. GAAP), entities must make appropriate adjustments (on a Schedule M) to properly account for income taxes. The ASU may change the timing of revenue recognition and, in some cases, the amount of revenue recognized for entities that maintain their books and records under U.S. GAAP or IFRSs. These changes may also affect taxable income because companies are often permitted to use the same methods for tax purposes as they use for financial accounting purposes. Thus, it will be important for tax professionals to understand the detailed financial reporting implications of the standard so that they can analyze the tax ramifications and facilitate the selection of any alternative tax accounting methods that may be available.

If a change in a tax accounting method is advantageous or expedient (including circumstances in which the book method has historically been used), the taxpayer will most likely be required to obtain approval from the relevant tax authorities to use the method. Similar implications may arise in foreign jurisdictions that maintain statutory accounting records under U.S. GAAP or IFRSs.

Looking Ahead

Although the ASU is not effective until annual periods beginning after December 15, 2016 (with a maximum deferral of one year for nonpublic entities that apply U.S. GAAP), O&G entities should start carefully examining the ASU and assessing the impact it may have on their current accounting policies, procedures, systems, and processes.

Appendix — Considerations for Nonpublic Entities

The FASB provided some relief for nonpublic entities through disclosure practical expedients and a delayed effective date. To use these reliefs, an entity cannot be any of the following:

  • A public business entity (as defined in ASU 2013-1212).
  • A not-for-profit entity that has issued, or is a conduit bond obligor for, securities that are traded, listed, or quoted on an exchange or an over-the-counter market.
  • An employee benefit plan that files or furnishes financial statements with or to the SEC.

Disclosure Practical Expedients

The following table summarizes the practical expedients that nonpublic entities can use to avoid providing certain of the disclosures required by ASU 2014-09 (the ASU’s disclosure requirements are covered in the Disclosures section above as well as in the left-hand column below):

Disclosure RequirementPractical Expedient for Nonpublic Entities

Present or disclose revenue and any impairment losses recognized separately from other sources of revenue or impairment losses from other contracts.

None.

A disaggregation of revenue to “depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors” (the ASU also provides implementation guidance).

An entity may elect not to provide the quantitative disclosure but should, at a minimum, provide revenue disaggregated according to the timing of transfer of goods or services (e.g., goods transferred at a point in time and services transferred over time).

Information about contract assets and liabilities (including changes in those balances) and the amount of revenue recognized in the current period that was previously recognized as a contract liability and the amount of revenue recognized that relates to performance obligations satisfied in prior periods.

An entity may elect not to provide the disclosures but should disclose the opening and closing balances of receivables, contract assets, and contract liabilities (if not separately presented or disclosed).

Information about performance obligations (e.g., types of goods or services, significant payment terms, typical timing of satisfying obligations, and other provisions).

None.

Information about an entity’s transaction price allocated to the remaining performance obligations, including (in certain circumstances) the “aggregate amount of the transaction price allocated to the remaining performance obligation[s]” and when the entity expects to recognize that amount as revenue.

An entity may elect not to provide these disclosures.

A description of the significant judgments, and changes in those judgments, that affect the amount and timing of revenue recognition (including information about the timing of satisfaction of performance obligations, the determination of the transaction price, and the allocation of the transaction price to performance obligations).

An entity generally must provide these disclosures but may elect not to provide any or all of the following disclosures:

  • An explanation of why the methods used to recognize revenue provide a faithful depiction of the transfer of goods or services to the customer.
  • For performance obligations satisfied at a point in time, the significant judgments used in evaluating when a customer obtains control.
  • The methods, inputs, and assumptions used to determine the transaction price, except that an entity must disclose the methods, inputs, and assumptions used to assess whether an estimate of variable consideration is constrained.

Information about an entity’s accounting for costs to obtain or fulfill a contract (including account balances and amortization methods).

An entity may elect not to provide these disclosures.

Information about the policy decisions (i.e., whether the entity used the practical expedients allowed by the ASU).

An entity may elect not to provide these disclosures.

In addition, a nonpublic entity is not required to provide the additional disclosures required of public entities on an interim basis.

____________________

1 FASB Accounting Standards Update No. 2014-09, Revenue From Contracts With Customers.

2 IFRS 15, Revenue From Contracts With Customers.

3 The SEC has indicated that it plans to review and update the revenue recognition guidance in SEC Staff Accounting Bulletin (SAB) Topic 13, “Revenue Recognition,” in light of the ASU. The extent to which the ASU’s guidance will affect a public entity will depend on whether the SEC removes or amends the guidance in SAB Topic 13 to be consistent with the new revenue standard.

4 For titles of FASB Accounting Standards Codification (ASC) references, see Deloitte’s “Titles of Topics and Subtopics in the FASB Accounting Standards Codification.”

5 Deloitte is represented on both the FASB and IASB joint transition resource group and the AICPA O&G industry task force.

6 ASU 2014-09 defines a customer as “a party that has contracted with an entity to provide goods or services that are an output of an entity’s ordinary activities in exchange for consideration.”

7 Although the ASU does not define goods or services, it includes several examples, such as goods produced (purchased) for sale (resale), granting a license, and performing contractually agreed-upon tasks.

8 “Probable” in this context has the same meaning as in ASC 450-20: “the event or events are likely to occur.” In IFRS 15, the IASB uses the term “highly probable,” which has the same meaning as the FASB’s “probable.” This is also consistent with the term “probable” in step 1 regarding the collectibility threshold. See Deloitte’s May 28, 2014, Heads Up for more information on collectibility.

9 Drilling contractors may also need to reevaluate their contracts upon the issuance of new leases guidance by the FASB and IASB, since such guidance could affect the determination of whether these contracts are or contain a lease.

10 O&G entities should consider whether straight-line recognition related to uneven pricing provisions indicates that the customer is financing the purchase of more expensive services later in the contract. See discussion above in Significant Financing Component.

11 Lifting costs are generally costs associated with O&G production after drilling is complete. Lifting costs include, but are not limited to, (1) transportation costs, (2) labor costs, (3) certain supplies, (4) cost of operating the wells, and (5) other expenses.

12 FASB Accounting Standards Update No. 2013-12, Definition of a Public Business Entity — An Addition to the Master Glossary.

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