Oil and gas operators, drilling contractors, and their trade associations have voiced concern about proposed accounting changes they fear would complicate contractual relationships, confuse investors, and raise administrative costs.
The proposal relates to leases of property and equipment. The changes would make companies account for leases with terms greater than 1 year as assets—or capitalized—in financial reports. They would not apply to leases of mineral rights but, as currently worded, potentially would treat drilling contracts as leases requiring new levels of reporting.
The Financial Accounting Standards Board and International Accounting Standards Board want to improve the ability of investors to compare financial performances of companies that lease much of their equipment and property with those favoring ownership.
Under present standards, explained an analysis this month by PricewaterhouseCoopers LLP (PwC), companies in many businesses can use leasing to take nearly full advantage of the benefits of outright ownership while avoiding the need to book debt and incur related interest expense. Their reported financial performances thus differ from disclosures of competitors that own corresponding assets, confounding comparisons by investors.
Drilling contractors argue treatment of their agreements with operating companies as leases under the new standards would make reports less comparable than they are now.
In a May exposure draft, the Financial Accounting Standards Board and International Accounting Standards Board proposed to require a company using equipment or property under leases longer than 1 year to calculate a value for each such lease and report it as a “right-of-use” asset on its balance sheet along with a related liability.
According to PwC, the asset initially would be equal to the lease liability plus any initial direct costs, which might include commissions or legal fees. The corresponding liability would be the present value of lease payments due over the lease term.
Under the exposure-draft proposal, income-statement handling of capitalized leases would depend on the nature of the lease.
Leases of equipment, called Type A, would be presumed to have higher expenses early than later in the lease term. The expenses would be allocated between interest and amortization.
Type B leases, covering property such as land, would be presumed to have constant, “straight-line” expenses over their terms.
PwC said the proposal introduces a concept of components, explaining an asset would be a separate lease component if the company could benefit from use of the asset and the asset wasn’t dependent on or highly interrelated with other underlying assets in the contract.
Each component would be accounted for as a separate lease.
Companies would have to establish processes for identifying lease components and conduct periodic reassessments, which PwC warned “may produce significant financial statement volatility.”
A comment period that ended Sept. 13 attracted responses from a number of oil and gas industry representatives, most acknowledging the need for changes in lease accounting in service to comparability while questioning the applicability to drilling contracts.
“The proposed accounting model introduces unnecessary judgments and complexity into revenue recognition, reduces the transparency of our financial information, reduces comparability of financial information across our peer group, and significantly increases the manpower required to administer the proposed model suggested by the exposure draft,” said a statement by James MacLennan, chief financial officer, and Dennis Lubojacky, chief accounting officer of Noble Corp.
The Noble representatives said drilling contractors “construct wells for our customers” and argued: “We generally object to any accounting model where equipment used in the delivery of construction services would be considered a lease obligation of the client (or a lease receivable to the contractor).”
David Meliza, of the International Association of Drilling Contractors Accounting Issues and Policies Committee, said the dayrate structure of current drilling contracts provides comparability. Contractors generally publish their fleet statuses and dayrates, enabling analysts to project revenues and compare companies.
“Assuming we are required to bifurcate the contract into a lease component and service component under the proposed standards, the dayrate would not continue to have this relationship with revenues,” he said.
Like many industry representatives, Meliza warned of new administrative burdens. Companies would have to reevaluate key terms quarterly and assess effects changes had on balances related to leases. Type A leases would require “relatively complex calculations that must be performed on a lease-by-lease basis.”
Patrick T. Mulva, chairman of the American Petroleum Institute General Finance Committee, said requirements proposed for Type A leases would end the “symmetry across partners” in specific wells or projects under joint agreements common in the oil and gas industry.
Mulva also warned of possible increases in administrative costs. “The implementation cost for most large companies with extensive use of contracts that may be considered leases under the proposal will likely run into the tens of millions of dollars for each company,” he said, adding, “Small and mid-sized companies would likely be required to invest millions of dollars to implement an accounting standard offering little incremental benefit to investors.”
Pengrowth Energy Corp., Calgary, suggested the exclusion related to mineral ownership be expanded to include surface rights. In Canada, oil and gas rights are separate from surface rights and generally are owned by provincial governments.
Contact Bob Tippee at firstname.lastname@example.org.