In 2018, the Accounting Standards Codification (ASC) Topic 606 became effective for all public companies. This major overhaul of revenue recognition has affected almost every industry, and oil and gas (O&G) companies are no exception. The complex arrangements between O&G companies, governments, and landowners pose some of the most difficult issues. Due to customized long-term contracts, contract modifications, and fluctuating commodity prices, application of the five-step revenue-recognition model can be particularly complicated.
In this article, we provide a brief explanation of the key issues the O&G industry faces when applying ASC 606, drawing on the following guides published by the AICPA and the major accounting firms.
- AICPA – Audit and Accounting Guide Chapter 18: Entities with Oil and Gas Producing Activities
- EY: Technical Line – Upstream, Midstream, Downstream
- PwC: Revenue: Implementation in the oil and gas industry
1. Production Imbalances
Upstream O&G companies routinely partner with other firms when extracting natural resources. The entities in these joint arrangements share the output from the site, and each party is free to sell or use its portion of the output as desired. Although the contractual agreement dictates the ownership split of the field’s total output over the life of the project, the output extracted by each partner may not align perfectly with his or her ownership percentage. The differences between an entity’s ownership percentage and its share of output are called production imbalances. These imbalances are tracked over time so that the parties involved can settle the differences.
Production imbalances often arise for practical reasons. It is more efficient for each partner to extract or “lift” a full tanker load at a time, rather than extract only the partner’s allotted share of output. Companies that have extracted more than their ownership interest in the field are overlifted while companies that have extracted less are underlifted.
Many of the largest accounting firms believe that using the sales method to account for production imbalances is most consistent with ASC 606’s methodology. Using the sales method, companies recognize revenue on all sales to third party customers, regardless of their ownership percentage. The underlifter and overlifter then adjust their claims on the asset’s remaining reserves to account for any production imbalances.
Spindletop Oil and Gas Co. is a public oil and natural gas exploration, development, and production company. In its 2019 10-K, Spindletop describes its accounting procedures for production imbalances:
The Company follows the “sales” (takes or cash) method of accounting for oil and natural gas revenues. Under this method, the Company recognizes revenues on oil and natural gas production as it is taken and delivered to the purchasers. The volumes sold may be more or less than the volumes the Company is entitled to take based on our ownership in the property. These differences result in a condition known as a production imbalance. Our crude oil and natural gas imbalances are insignificant.
2. Production Sharing Arrangements (PSAs)
Production sharing agreements (PSAs) are agreements through which governments give O&G entities the right to extract natural resources from government property while sharing in production profits. The O&G company assumes the financial risk of the operation by paying for the exploration costs and some or all the development and production costs. Through this arrangement, governments can leverage the O&G company’s operational expertise and avoid risks inherent in hydrocarbon exploration. O&G companies also benefit by gaining access to natural resources that would otherwise be restricted.
If an exploration project is successful, the company will be refunded for its costs via the proceeds of the project. Once the company’s costs have been fully refunded, the government and O&G company share any additional profits according to an agreed-upon profit margin.
When accounting for PSAs, each agreement should be analyzed separately to determine whether the government is considered a customer under ASC 606.
If the government is considered a customer, the contract falls within the purview of ASC 606. The O&G company would recognize revenue for any services performed (like exploration and construction services) on behalf of the government in exchange for future production. The future production would be considered variable non-cash consideration and change the company’s revenue measurement. If the government is not considered a customer, then the contract is outside the scope of ASC 606. The O&G company’s portion of the proceeds should be recognized as revenue when its share of production is delivered to end customers. Also, the costs associated with producing the government’s share of output should be classified as an operating expense, not cost of goods sold.
3. Contract Modifications: Blend and Extend Arrangements
O&G companies often enter into “blend and extend” arrangements, where the supplier and customer renegotiate an existing contract by adjusting the pricing and extending the life of the contract. For example, if commodity prices have dropped, the customer may negotiate a lower “blended” rate between the original contract rate and the current market price. The supplier also benefits by guaranteeing future demand via the contract extension.
Per ASC 606, O&G companies must first determine whether the modification should be treated as a new contract. If additional goods or services are added to the contract and the price of these goods or services reflects their standalone selling prices, the remaining arrangement should be considered a separate contract for accounting purposes.
If the contract modification results in a separate contract, the payment terms of the newly created contract should be evaluated for the existence of a significant financing component. The blended rate may cause some of the payment for goods and services to precede delivery, which may be evidence of a significant financing component.
If additional goods or services are added with either higher or lower consideration than their standalone selling prices, the arrangement is not treated as a separate contract. Instead, the old contract is terminated, and a new contract is created in which the new rate will be applied prospectively to the remaining goods yet to be provided to the customer (from the original contract and the extension period).
As at December 31, 2020, a contract asset of $51 million ($50 million net of credit losses) has been recorded within long-term investments and other assets on the Consolidated Balance Sheets (December 31, 2019 – $30 million). This contract asset represents the difference in revenue recognized under a new rate in a blend-and-extend contract modification with a customer. Revenue from this contract modification will be recognized at the pre-modification rate for the remainder of the original term with the excess revenue recorded as a contract asset. The contract asset will be drawn down over the remaining term of the modified contract.
4. Pricing Considerations as Part of Commodity Prices
Many sales contracts relating to commodities include provisional pricing, which establishes a temporary price that may be adjusted in the future. Due to lengthy transportation routes, customers who prefer a price close to the market price on the date of delivery rather than the date of shipment may request a provisional pricing arrangement. Another common scenario that gives rise to provisional pricing occurs when commodities are transferred in concentrate form and the final volume or quality is not known until further processing. Often the final price associated with these types of transactions is an average market price over an agreed-upon period.
Management must carefully consider whether the contract includes an embedded derivative that should be accounted for separately per ASC 815 – Derivatives and Hedging. Management should also analyze the contracts to determine the overall transaction price and re-assess the transaction price each reporting period.
Variable consideration may be a significant portion of the transaction price in contracts where the delivered products will be subject to further processing. ASC 606 includes a constraint that management should only recognize variable consideration that is “not probable” to undergo a significant revenue reversal in the future.
5. Delivery: CIF v. FOB
O&G companies often extract natural resources from remote locations and transport them over long distances to the customer. Within the industry, the two main forms of shipping contracts are (1) cost, insurance, freight (CIF) and (2) free on board (FOB). Under CIF contracts, the seller assumes the risk of loss during transport by paying for the cost, insurance, and freight related to the shipment. Under FOB contracts, the buyer assumes these risks while the product is in transit.
The timing of revenue recognition under ASC 606 depends on the transfer of control for the purchased product. Although ASC 606 does not specify exactly how to tell when control has been transferred, it establishes several key indicators of control transfer including the seller’s right to payment, the transfer of legal title, the physical transfer of the goods, and the customer’s acceptance of the risks and rewards of ownership.
Many O&G contracts include provisions that articulate when product titles will be transferred, and these clauses are often used as evidence of a transfer of control. Control transfer may not align with the physical delivery of goods. For example, control of the commodities may be transferred when the product is shipped, although the physical delivery may only be complete when the product arrives at its destination.
CIF Accounting Treatment Under ASC 606
If the transfer of control occurs after shipment, any shipping costs paid by the seller are not treated as a separate promise to the customer. The company is effectively transferring its own goods and does not create a separate performance obligation for these activities. All revenue related to the contract would be recognized when the goods are delivered, and control has been transferred.
If the transfer of control occurs before shipping, any shipping costs paid by the seller may be treated as a separate performance obligation. Some factors that would indicate a separate performance obligation include the need for specialized transportation; the cost, timeliness or distance of the delivery; and the ability for customers to opt out of the transportation portion of the contract and collect the commodity themselves. If a separate performance obligation is identified, some revenue would be recognized upon shipment and additional revenue relating to the transportation services would be recognized over the period of delivery.
The FASB has approved a practical expedient that allows companies to treat shipping costs as a fulfillment cost rather than a separate performance obligation if the transfer of control occurs before transportation activities.
FOB Accounting Treatment Under ASC 606
Since sellers have no obligation to pay for transportation activities in an FOB contract, ASC 606 should not affect the timing of revenue recognition in these contracts. In most FOB contracts, all revenue should be recognized upon shipment. Control is effectively transferred upon shipment, coinciding with both title transfer and physical delivery.
6. Take-or-pay Contracts and Other Long-term Supply Arrangements
In the O&G industry, producers and buyers often enter into long-term sales contracts over a year in duration. These long-term contracts usually specify the amount of commodity to be delivered and the transaction price. Given the volatile nature of commodities prices, sales contracts often include clauses allowing for price adjustments if the underlying commodity prices change drastically over the life of the contract.
Take-or-pay arrangements between O&G suppliers and customers ensure that the customer will either “take” product from the supplier or “pay” a penalty. The two parties agree on a price at which the customer will buy product and another price, usually lower, that serves as the penalty if the product is not accepted by the customer. This structure of contract guarantees the supplier a minimum level of future demand, thus reducing risk and allowing the supplier to lower its prices.
The first step in accounting for take-or-pay and other long-term contracts is to consider whether the contract contains any embedded derivatives or qualifies as a lease. In these situations, management should refer to the relevant accounting guidance: ASC 842 – Leases and ASC 815 – Derivatives and Hedging.
If no other accounting standards apply, companies should treat product deliveries (the “take” scenario) like any other transaction under ASC 606. Additional accounting complications arise when the customer opts to pay a penalty instead of receiving product (the “pay” scenario). Product quantities that a customer chooses not to take are called deficiency quantities. The revenue associated with these penalties classifies as breakage under ASC 606.
Breakage describes situations where customers do not exercise their rights to receive goods or services. Under ASC 606, companies can only recognize the future payment penalties as breakage revenue prior to the expiration of the customer’s exercisable rights if they can reliably estimate the amount of future payment penalties. Otherwise, the companies can only recognize breakage revenue after the customer’s rights to the product have expired. Unexpected breakage should be recognized as revenue when the customer’s probability of exercising their rights becomes remote. Management should re-evaluate their breakage estimates each reporting period. Some take-or-pay contracts allow customers a makeup period during which they can reclaim goods which they previously elected not to receive (the “pay” scenario). The prior payment penalty counts towards the cost of the reclaimed goods in the subsequent period; however, customers do not receive a discount on the reclaimed goods and must make additional payments if the price of the goods has risen. In contracts with a makeup period, O&G entities still have performance obligations to deliver goods at the customer’s request even after the customer chooses not to receive the product. Like the original breakage scenario, O&G entities can recognize revenue for deficiency amounts which they do not expect the customer to request in the future. The remaining revenue would be deferred until the customer reclaims the goods or the option to do so expires.
Hess Corp. is a public company involved in the exploration and production of oil and natural gas. In its 2019 10-K, Hess describes how it accounts for take-or-pay provisions under ASC 606:
For long-term international natural gas contracts with ship-or-pay provisions, our obligation to stand-ready to provide a minimum volume over each commitment period represents separate, distinct performance obligations. Penalties owed against future deliveries of natural gas due to delivery of volumes below minimum delivery commitments are recognized as reductions to revenue in the commitment period when the shortfall occurs. Long-term international natural gas contracts may also contain take-or-pay provisions whereby the customer is required to pay for volumes not taken that are below the minimum volume commitment, but the customer has certain make-up rights to receive shortfall volumes in subsequent periods. Shortfall payments received from customers when volumes purchased are below the minimum volume commitment are deferred upon receipt as a contract liability. Revenue is recognized at the earlier of when we deliver the make-up volumes in subsequent periods or when it becomes remote that the customer will exercise their make-up rights.
7. Identifying Separate Performance Obligations
Under ASC 606, management should analyze each activity related to a customer contract to determine whether the activity is a separate promise to the customer. Within the O&G industry, some examples of these services include gathering, processing, and compression services provided by midstream companies and drilling, mobilization, and standby services provided by oilfield services companies. The remainder of this section focuses specifically on drilling contracts, but the principles remain true for other types of O&G contracts involving multiple services.
O&G entities routinely sign complex drilling contracts that require the use of specialized equipment to provide various types of pre-extraction services. Many such drilling contracts include “mobilization” or “localization” terms, which require the driller to move equipment, like a drill rig, to the drilling site. When analyzing drilling contracts, O&G companies must determine whether the transportation of equipment should be classified as a separate performance obligation. Per ASC 606-10-25-17, “performance obligations do not include activities that an entity must undertake to fulfill a contract unless those activities transfer a good or service to the customer.”
If the mobilization of equipment is necessary to fulfill the overarching drilling contract, then it should not be treated as a separate performance obligation. Instead, the mobilization service should be treated like the set-up required to complete a broader customer promise. In this instance, the mobilization costs should be capitalized according to the guidance in ASC 340-40. All payments or reimbursements related to the mobilization process should be allocated to the contract’s performance obligations (non-mobilization activities). Any upfront payments should be treated as deferred revenue and recognized as revenue in accordance to the timing of the related performance obligation (i.e. the drilling service).
If the mobilization is determined to be a separate promise to the customer and is both “capable of being distinct” and “distinct within the context of the contract,” then these activities should be treated as a separate performance obligation. The service provider should start recognizing revenue related to this performance obligation when the mobilization activities commence, not when drilling begins.
8. Volumetric Optionality
Many upstream and marketing companies enter into contracts that include options for additional goods or services. Customers have the opportunity (but not the obligation) to change the amount, or volume, of commodity purchased based on market conditions. These options are routinely included in take-or-pay and other off-take arrangements. (See Topic 7 for more information about these types of contracts.)
O&G companies should analyze each agreement to determine whether the option represents a separate performance obligation. Often, the accounting treatment for a contract with an option to purchase additional goods or services is identical to a contract without that option. For example, an option to buy goods at the company’s regular retail prices does not represent an additional benefit to the customer because the customer would have had access to those prices without the prior purchase.
An exception to this rule occurs when the option includes a “material right.” Per ASC 606-10-55-42, a material right is a benefit that the customer “would not receive without entering into the contract,” such as a discounted price beyond the company’s regional pricing policies. Thus, an option with a material right functions similarly to an advance payment for services and should be treated as a separate performance obligation within the original contract.
In many O&G contracts, the existence of an option requires an up-front payment determined by the commodity’s forward commodity price curve. The up-front payment should be included in the contract’s overall transaction price and allocated to the appropriate performance obligation(s) per ASC 606. The contract should also be evaluated for the existence of a significant financing component. (See Topic 12 for more information on significant financing components.)
9. Principal v. Agent Considerations
Within the O&G industry, companies often provide additional services beyond selling extracted natural resources. Some of these value-added services include transportation services, technical expertise, and refining activities. When performing these services, companies must determine whether they are acting as principals or agents. The revenue recognition guidance outlined in ASC 606 has changed the process by which principal-agent relationships are determined by emphasizing the concept of control.
If the company obtains control of another party’s goods prior to transferring these goods to the customer, the company is acting as a principal. Some of the indicators that suggest a company is acting as a principal include primary responsibility for fulfilling the contract, inventory or customer credit risk, and pricing power. When serving as a principal, the company recognizes revenue on the gross contract value. If the company merely arranges for another entity to provide services, the company is acting as an agent. When acting as an agent, the company recognizes revenue on its commission or fee, if one exists. The total revenue from the contract will equal the “net” amount after paying the principal for the goods or services.
Equus Total Return is a platform for various investment strategies, including ventures in the oil and gas space. In its Q1 2020 10-Q filing, Equus describes how it analyzes transactions involving a principal and an agent:
An entity acting as a principal records revenue on a gross basis if it controls a promised good or service before transferring that good or service to the customer. An entity is an agent if it does not control the promised good or service before transfer to the customer. If the entity is an agent, it records as revenue the net amount it retains for its agency services. However, due to the uncertainty of the variable pricing component and the separation of expenses billed to the Company from the consideration processed and paid by the operator, the revenue is recorded at net.
Under the Company’s normal operating activity arrangements, the operator is responsible for negotiating, fulfilling and collecting the agreed-upon amount from the sale with the end customer and is, therefore, determined to be acting as agent on behalf of the Company. The principal versus agent consideration will continue to be assessed for new contracts, both within and outside the company’s normal operating activities.
10. Significant Financing Component
Sales contracts that require the customer to pay substantially before (or after) the delivery of the good or service may indicate that the seller is receiving (or providing) financing in conjunction with the sale. Under ASC 606, entities must recognize interest expense (or revenue) if the contract includes a significant financing component.
Many O&G contracts include up-front fees or extended payment terms, which may qualify as a form of financing under ASC 606. The revenue standard may require companies to adjust revenue recognition for the time value of money if the contract terms include a significant financing component.
Extended Payment Terms
For contracts with extended payment terms, revenue under ASC 606 should be recognized when the entity transfers control of the good or service to the customer and there is no deferral of revenue tied to the timing of payments.
Many downstream companies, including refiners, enter into agreements to license their brand or intellectual property to dealer-owned, dealer-operated stores. These arrangements can take many forms including branded-fuel agreements, franchise agreements, and sales-based royalty agreements. In each variation, the refiner provides fuel to the dealer who then sells the fuel to the end customer. The payment mechanisms vary between fixed fee arrangements and percentage-based royalty payments. Due to the complexity of these agreements, we recommend taking special care when determining how to account for these contracts. (For more information see the EY guide listed in the resource section of this article.)
Some O&G entities provide access to seismic data libraries to their clients. Under ASC 606, these licenses may classify as a separate performance obligation. Companies should determine whether the licenses provided are distinct by considering whether: (1) the customer can benefit from the license on its own and (2) the license is separately identifiable from the other promises in the contract. Determining whether the seismic licenses are distinct requires significant judgement. Reviewing the implementation efforts of the software and cloud services industries, which face similar licensing issues, may add additional insight into this topic.
12. Operating Expense Reimbursements
Many O&G companies grant partial ownership in a mineral field to other O&G entities, in exchange for their help in developing and operating the fields. When one company incurs overhead costs for the entire field, it will often request reimbursement from the other owners in proportion to their ownership percentage. These reimbursement costs must be analyzed to determine whether the payments should be classified as revenue or an expense reduction.
Generally, reimbursement payments for operating expenses reflect an interest owner’s fulfillment of promises made in the partnership agreement, not a vendor-customer relationship. As such, operating expense reimbursements should be accounted for as an expense reduction. This line of thinking is consistent with ASC 606-10-15-3, which states that agreements with entities in which both parties “share in the risks and benefits that result from the activity or process” do not qualify as client-customer relationships.
Under some circumstances a relationship with a customer may exist and the reimbursements should be treated as revenue. For example, an entity may provide services to joint interest owners and third parties within the same mineral field. The services provided to the third-parties may qualify as a performance obligation under ASC 606 and result in revenue recognition.
13. Estimating Production
To prepare financial statements in a timely manner, accountants within the O&G industry must estimate future production levels when recognizing revenue. For example, management must recognize revenue on the proceeds from gas production upon delivery, even though the actual production can only be determined one to three months afterwards.
The AICPA’s Financial Reporting Executive Committee (FinREC) believes that using estimated output figures is appropriate if the actual volumes are not known in time to allow for timely preparation of the financial statements. Any discrepancies between the estimated sales volume and the actual amount should result in an adjustment to revenue in subsequent periods. This form of revenue recognition is subject to the variable consideration constraint found in ASC 606-10-32-11.
In its 2018 10-K filing, Brazos Valley Longhorn describes how it accounts for production estimates under ASC 606.
We record revenue in the month oil or natural gas volumes are delivered to the customer, based on estimated production, prices and revenue deductions. Any variances between our estimates and the actual amounts received are generally recorded one month after delivery for operated oil sales, two months after delivery for operated natural gas and NGL sales and three months after delivery for non-operated oil, natural gas and NGL sales.
It is likely that many other issues and questions will continue to arise within the O&G industry as entities apply the revenue recognition standard. This article serves as a base reference point for your research into some of the focal issues experienced by industry experts. Similar industry-specific issues and resources are available on the RevenueHub site for all major industries as identified by the AICPA.