Deloitte's Roadmap: Environmental Obligations and Asset Retirement Obligations

In the United States, the U.S. Environmental Protection Agency (EPA) is the primary, though not the only, environmental regulator. Other federal, tribal, state, or local agencies may also have authority to regulate environmental programs. The guidance on accounting for environmental liabilities classifies laws into two categories: (1) environmental remediation liability laws and (2) laws intended to control or prevent pollution. The following are some of the main federal regulations that serve as drivers of environmental liabilities:

• The Clean Air Act of 1970 (CAA).
• The Clean Water Act of 1972 (CWA).
• The Toxic Substances Control Act of 1976 (TSCA).
• The Resource Conservation and Recovery Act of 1976 (RCRA).
• The Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (CERCLA or the “Superfund”).

When the recognition criteria are met, entities initially measure environmental remediation liabilities at the estimated cost of remediating the site; generally, environmental remediation liabilities are not discounted unless certain conditions are met. Estimated remediation costs are continually updated, and the recorded liability is adjusted prospectively until the obligation is settled.

In a manner consistent with the guidance in ASC 450-20 and ASC 275 on other loss contingencies and uncertainties, entities are required to disclose the existence of environmental remediation loss contingencies when it is at least reasonably possible that a loss has been incurred regardless of whether the loss is reasonably estimable. Additional disclosure requirements exist for recognized environmental remediation loss contingencies.

An ARO is recognized at fair value when incurred or when a reasonable estimate of its fair value can be made. An asset retirement cost (ARC) is recorded by increasing the associated long-lived asset’s carrying value. The ARC is depreciated over the useful life of the long-lived asset. An ARO liability is discounted and recorded at present value, and accretion of an ARO liability due to the passage of time is recognized as a component of operating expense. Revisions to the estimated timing or amount of cash flows associated with the retirement activities are recognized as an increase or decrease in the carrying amount of the ARO and the related ARC.

Application of the guidance in ASC 410-20 can be complex and requires significant management estimates and judgment. For example, determining whether a legal obligation to retire a long-lived asset has been incurred may not always be clear and unambiguous. If an entity makes a promise to a third party, including the public at large, about its intentions to undertake asset retirement activities, significant judgment may be required in the determination of whether the entity has created a legal obligation under the legal doctrine of promissory estoppel, which is defined in ASC 410-20-20 (citing Black’s Law Dictionary, seventh edition) as the “principle that a promise made without consideration may nonetheless be enforced to prevent injustice if the promisor should have reasonably expected the promisee to rely on the promise and if the promisee did actually rely on the promise to his or her detriment.”

Concurrently with the SEC’s ongoing rulemaking activities related to climate disclosures, its Division of Corporation Finance (the “Division”) continues to issue comment letters to registrants in various industries regarding climate-change disclosures. The Division has publicly released such comment letters and registrants’ responses to them.

In the forthcoming regulatory environment, it will be essential for companies to closely monitor their environmental obligations under new or changing laws and regulations.

For some air pollution problems (e.g., acid rain, ozone layer protection, vehicle emissions, and certain stationary source programs involving common pollutants), the CAA Amendments encourage the use of market-based principles, such as performance-based standards and emissions banking and trading.

For example, in allowance trading, affected sources such as utilities are required to install systems that continuously monitor emissions of sulfur dioxide (SO2), nitrogen oxides (NOx), and other related pollutants to track progress and ensure compliance. Entities that reduce their emissions below their held number of allowances may (1) trade allowances with other entities in their system, (2) sell them to other entities on the open market or through EPA auctions, or (3) bank them to cover emissions in future years.

RCRA encompasses several different program areas to ensure compliance with statutes and regulations in the management of hazardous waste and underground storage tanks. For example, Subtitle D of RCRA pertains to nonhazardous solid waste requirements. Regulations established under Subtitle D ban open dumping of waste and set minimum federal criteria for the operation of municipal waste and industrial waste landfills, including design criteria, location restrictions, financial assurance, corrective action (or cleanup), and closure and postclosure requirements. States assume a lead role in implementing these regulations and may set more stringent requirements than those in Subtitle D. In the absence of an approved state program, the federal requirements apply.

Subtitle C of RCRA pertains to the regulation of hazardous waste. Under Subtitle C, the EPA may authorize states (in lieu of the federal government) to implement key provisions of hazardous waste requirements. If a state program does not exist, the EPA implements the hazardous waste requirements in that state. Subtitle C regulations set criteria for (1) hazardous waste generators, (2) transporters, and (3) treatment, storage, and disposal facilities. The criteria include permit requirements, enforcement, and corrective action or cleanup.

The Superfund Amendments and Reauthorization Act of 1986 (SARA) incorporated various site-specific amendments, definitions, clarifications, and technical requirements within CERCLA, including additional enforcement authorities, settlement provisions, and criminal sanctions for blatant violations. Title III of SARA is the Emergency Planning and Community Right-to-Know Act (EPCRA), which was designed to help protect communities from chemical hazards to public health, safety, and the environment. EPCRA requires hazardous chemical emergency planning by federal, state, and local governments; Indian tribes; and private industry. Under EPCRA, private industry is required to report to federal, state, and local governments on its storage, use, and release of hazardous chemicals.

The Superfund site assessment process begins with site discovery or notification of a release or potential release into the environment. The EPA may be notified of hazardous waste activity by citizens, states, tribes, or other environmental programs. After notification, nonfederal sites undergo prescreening for a determination of whether the Superfund site assessment process is appropriate. Sites that are identified as appropriate for the process are assigned a site discovery date and added to the EPA’s active CERCLA site inventory.

Once a site is added to the CERCLA site inventory, a site assessment for determining whether the site warrants short-term or long-term cleanup is performed by the EPA or under the environmental program of a state, a tribe, or another federal agency. In site assessments, data are collected so that hazardous waste sites can be identified, evaluated, and ranked on the basis of Hazard Ranking System (HRS) criteria. The HRS is a numerically based screening system that uses information from initial limited investigations to assess the relative potential threat that sites may pose to human health or the environment. Sites with an HRS score below 28.51 generally require no further Superfund remedial attention and receive a “no further remedial action planned” designation. Sites that require additional study are referred to appropriate cleanup programs, including (1) the Emergency Response and Removal Program, (2) the RCRA Corrective Action program, (3) state and tribal cleanup initiatives such as voluntary cleanup programs (VCPs), (4) the Superfund alternative approach, and (5) the NPL. Note that only sites listed on the NPL are eligible for Superfund Trust Fund–financed remedial actions. The flowchart below illustrates the site assessment process.

In 2017, the EPA added subsurface intrusion as a component of the HRS. This addition allows the EPA to consider and score the threat posed by subsurface intrusion in its HRS analysis. Subsurface intrusion is the migration of hazardous substances or pollutants and contaminants from the unsaturated zone and the surficial groundwater into overlying structures. Although subsurface intrusion can occur through multiple mechanisms, the most common form is vapor intrusion. In 2018, the EPA added two sites to the NPL on the basis of vapor intrusion alone. The listing of these sites may serve as precedent for other sites to be added solely for vapor intrusion. Although most sites that have vapor intrusion are also ranked under the HRS for other exposure pathways, manufacturers may want to consider their current and former facilities to determine whether vapor intrusion poses a significant risk and, if so, whether further investigation or remediation is warranted.

Companies directly affected by the 2018 NPL listing, together with industry groups, expressed concern about the EPA’s unprecedented decision to include a site on the NPL solely on the basis of a subsurface intrusion pathway. One company filed suit against the EPA in the hope of overturning that decision. In July 2020, however, the U.S. Court of Appeals for the D.C. Circuit denied the company’s petition for review. The federal appellate court’s ruling is likely to affect the evaluation and remediation of contamination beneath manufacturing, chemical, and other industrial facilities around the country. In addition, the court’s affirmation of the EPA’s first NPL listing of a Superfund site due exclusively to subsurface intrusion of hazardous substances will inform listing decisions at other sites with subsurface contamination. The precedent that the court’s ruling establishes may result in the inclusion of more sites on the NPL based solely on the existence of subsurface intrusion pathways.

Therefore, placement on the NPL does not in itself (1) reflect a judgment of the activities of site owners or operators, (2) require those persons to undertake any action, or (3) assign liability to any person.

Generally, after a site has been placed on the NPL, the EPA will send “notice of liability” letters to PRPs for contaminating the site (see Section 2.3.7).

As part of the remedial investigation, the PRP, EPA, or both collect data to characterize site conditions, determine the nature of the waste, assess risk to both human health and the environment, and conduct treatability testing to evaluate the potential performance and cost of the treatment technologies being considered. The data are then evaluated in the feasibility study across a range of alternative remedial actions.

The feasibility study has two main components: (1) development and screening of remedial action alternatives and (2) comparison of each alternative that passes screening in a detailed analysis. A range of remedial action alternatives, including cost estimates for each, is developed during the feasibility study as data from the remedial investigation site characterization become available. Treatability studies help reduce uncertainties related to cost and performance of treatment alternatives.

When a site has been proposed for inclusion on the NPL, the EPA typically determines which entities fall within the categories listed above before issuing a “notice of liability” letter. After identifying PRPs, the EPA uses “general notice” letters and “special notice” letters to communicate with them.

A general notice letter informs the recipient that it (1) has been identified as a PRP at a Superfund site and (2) may be liable for cleanup costs at the site. The letter explains the process for negotiating the cleanup with the EPA, includes information about the Superfund and the site itself, and may include a request for additional information. General notice letters are typically sent to PRPs early in the process, such as when a site has been proposed for inclusion on the NPL. Upon receiving a general notice letter from the EPA, a PRP should evaluate whether recognition of an environmental remediation liability is required under ASC 410-30. See Section 3.3 for further discussion of the recognition of environmental remediation liabilities.

The EPA issues a special notice letter when it is ready to negotiate with PRPs to clean up a site (i.e., at either the remedial investigation and feasibility study stage or the remedial design/remedial action stage). A special notice letter explains to PRPs why the EPA thinks that they are liable and informs them about the EPA’s plans for the site cleanup. The letter also invites parties to participate in negotiations with the EPA on performing future cleanup work and reimbursing the EPA for any site-related costs already incurred. The issuance of a special notice letter triggers a “negotiation moratorium,” meaning that the EPA agrees, for a certain period, not to unilaterally order the PRP to conduct the cleanup. Although the EPA generally issues special notice letters to PRPs, it may decide not to do so in the following circumstances:

• Past experience with the PRPs indicate that a settlement is unlikely.
• No PRPs have been identified.
• PRPs lack the resources to do what is needed.

ASC 410-30 includes the following guidance on liability under CERCLA:

PRPs can enter into various types of Superfund settlement agreements with the EPA. Such settlement agreements are summarized in the table below.

States are asked to implement and enforce federal laws while retaining the power to create laws that are more stringent than federal laws. Thus, the vast majority of federal environmental laws are implemented by states. The same is largely true for Indian tribes, which remain sovereign over their lands. In incorporating cooperative federalism principles into environmental laws, Congress has recognized the roles that states have historically played as protectors of their resources, as well as the local nature of many environmental issues.

In a federal-state partnership, state environmental regulations implement the federal environmental regulatory requirements. Further, in circumstances in which federal environmental statutes are silent about a state’s responsibility to implement the requirements, states have developed and implemented environmental laws to protect local environmental resources. Most importantly, for companies managing environmental liabilities, each state has implemented environmental cleanup statutes and regulations to enforce the remediation of releases of hazardous substances into the environment. When the complexity and hazards of contamination do not rise to the level of the Superfund, which is regulated by the EPA, the states regulate the environmental cleanup activities at the local level.

Such procedures require an owner or operator to notify the state regulatory agency if contamination has been identified at concentrations that exceed specified “action levels” defined in the applicable rules. For example, under the Texas Risk Reduction Program (TRRP) regulated by the Texas Commission on Environmental Quality (TCEQ), when there is an actual or probable human exposure to a COC at a concentration that exceeds the Tier 1 human health protective concentration limit (the Texas “cleanup standard”), the regulated entity must notify the TCEQ of the contamination and then conduct response actions specified under TRRP. That is, even if the state regulatory agency has not initiated an enforcement action, the regulated entity has an obligation under the state environmental statute to notify the regulator and then conduct cleanup activities in compliance with the state environmental regulatory regime. Most state environmental regulations impose a similar notification provision to ensure that the regulator and any potentially affected parties (e.g., neighboring property owners) are properly notified.

Most of these regulations allow regulated entities to pursue environmental remediation activities under one of the following schemes:

• Corrective action programs — The state regulator uses a “command-and-control” method to lead remediation activities. Legal documents such as administrative orders may be used to direct the action, and the regulated entity must receive approval from the regulator at each step of the process. This process is similar to that for remediation activities regulated by the EPA under CERCLA and RCRA.
• Voluntary cleanup/remediation programs — The regulated entity (sometimes called the “volunteer”) leads remediation activities and receives administrative, technical, and legal incentives from the state regulator to encourage cleanup of contaminated sites. State voluntary cleanup programs (VCPs) usually allow the entity to use risk-based cleanup principles, discussed below, in determining site-specific cleanup standards and remedial approaches.
  Note that the term “voluntary” does not mean that the remediation activities are optional or discretionary. If a regulated entity does not proceed under the VCP, the state has the authority to direct the cleanup under a corrective action or similar program. Therefore, since a company’s obligations under a state VCP are not undertaken voluntarily and at the sole discretion of management, they are considered to be environmental obligations and should be accounted for under the guidance in ASC 410-30.

States with transfer laws that similarly impose an obligation to perform assessment and remediation activities in connection with a transaction include, but may not be limited to, the following:

• Connecticut — The Connecticut Transfer Act applies to the transfer of (1) establishments at which hazardous waste is or was generated, (2) establishments to which hazardous waste was brought from a different location, and (3) certain defined business operations. The Transfer Act requires the transferor to notify both the transferee and the Connecticut Department of Energy and Environmental Protection at the time of transfer about whether a release of hazardous waste or substances has occurred at the establishment. If such a release has occurred, one of the parties to the transaction must commit to cleaning it up.
• Delaware — The Delaware Transfer or Closure of Establishments Law requires that, during the transfer of properties or operations, or the termination of operations at which at least one million pounds of hazardous substances are used or generated, environmental investigations be performed and financial assurances established to ensure that the site will be stabilized or secured.

Other states, such as California, Iowa, Michigan, and Oregon, do not specifically mandate environmental cleanup as a prerequisite to transactions but require disclosure of environmental conditions before the transfer of an interest in real property or a business. A seller with knowledge of an actual or suspected hazardous substance release must disclose to the buyer the general nature and extent of the release. Failure to comply with the disclosure requirements may impose civil and criminal liability, as well as harsh penalties such as strict liability for the cost to remediate the release.

In 1993, the Massachusetts Department of Environmental Protection implemented new rules for reporting, assessing, and cleaning up releases of oil and hazardous material. Collectively known as the Massachusetts Contingency Plan (MCP), the rules lay out a detailed process for when and how contaminated sites must be assessed and cleaned up. The rules privatized the cleanup of contaminated sites in Massachusetts to allow the state to focus its limited resources on the tasks requiring government attention. Under the MCP, responsible parties are required to hire a licensed site professional (LSP) to manage and oversee the required assessment and cleanup activities. An LSP is an environmental scientist or engineer experienced in the cleanup of oil and hazardous material contamination. The LSP works with responsible parties to develop and execute a scope of work that will satisfy the state requirements set forth in the MCP for addressing contaminated property.

In 2009, New Jersey reformed its site remediation process to shift much of the responsibility for remediation oversight and approvals from the NJDEP to private contractors. These contractors must meet the state licensing requirements for certification as licensed site remediation professionals (LSRPs) and are required to comply with all remediation statutes and rules. They are bound by a strict code of ethics, violation of which could result in the assessment of penalties and suspension or revocation of an LSRP’s license. In most situations, the NJDEP is not required or authorized to (1) review and approve investigation and cleanup plans in advance or (2) issue NFA letters at the conclusion of cleanup activities. Rather, the LSRPs determine the propriety of the work at the conclusion of the investigations and cleanups and issue the final sign-off document, known as the “response action outcome” (RAO). An LSRP issues an RAO only after a site has been properly investigated and remediated in accordance with the remediation standards and technical requirements for site remediation. The NJDEP monitors the LSRP’s remediation progress and actions by requiring that forms and reports be submitted as remediation milestones are reached.

In Connecticut, LEPs are authorized to work on sites that qualify as “establishments” if a transfer of ownership is involved. Under the Connecticut Transfer Act, an establishment is any facility where dry cleaning, furniture stripping, or auto body repairs have been conducted; any facility where hazardous waste has been treated, stored, recycled, handled, or disposed of; or any other facility where more than 100 kilograms of hazardous waste has been generated in any one month. LEPs may also investigate and remediate contaminated sites under the voluntary remediation program and verify that a parcel has complied with remediation standard regulations.

As a result of licensing programs, the time required to complete remediation activities has decreased in the states noted above. Before the licensing programs were established, cleanups at some sites took more than 20 years to complete because of delays associated with state agency review and approval turnaround times. Now that the LEP is the decision maker, cleanups in most cases are driven by the real estate market and are performed in less time than the period allowed by statute. All three states report that the rate of site closure exceeds the rate of discovery and that case backlogs have therefore decreased.

The basic premise of risk-based remediation is that the decision to remediate a site should be based on the need to reduce the actual or potential risk that specific contaminants pose to human or ecological receptors. Risk-based decision-making involves (1) the evaluation of current and reasonably likely future risks to human health and the environment associated with contamination at a site and (2) use of that information to develop the best combination of cleanup and site management to reduce risks to acceptable levels. The process includes identification of hazards, assessment of exposure and toxicity, characterization of risk, and informed decision-making. Fully informed decisions about potential remedial actions cannot be made without adequate site characterization to identify the nature and extent of contamination. This information is gathered during site assessment processes and presented in a conceptual site model or similar assessment report.

As noted in Section 2.3.4.2.5, for a risk to exist, there must be (1) a source of chemical release, (2) a human or ecological receptor that is potentially exposed to the released chemicals, and (3) an environmental exposure pathway connecting the source and the receptor(s). The chart below lists examples of these elements.

If any of these elements is absent, the exposure pathways are incomplete and no risk is present. If a risk is present, it may be reduced or eliminated through (1) removal of the source or receptor or (2) interruption of the pathway. The goal of risk-based remediation is to reduce present and future risk in a cost-effective manner through the use of one or more of the following risk reduction techniques:

• Chemical source reduction — Achieved by physical removal or control of the COCs.
• Receptor restriction — Land use controls (e.g., restrictive covenants) and physical barriers (e.g., concrete caps and site fencing) can prevent COC exposure until source concentrations are reduced below risk levels.
• Chemical pathway elimination — Examples include placing restrictions on excavation or groundwater use to prevent on-site or off-site receptors from making contact with chemicals of concern.

Risk-based cleanup standards provide greater flexibility because they are based on actual land use (e.g., commercial or industrial) rather than unrealistic maximum exposure assumptions (e.g., pristine conditions). If future land use can be controlled and groundwater use can be restricted, less stringent cleanup standards can be applied because risk is mitigated. Risk-based cleanup standards allow flexibility to choose between a more rapid and costly remediation approach, which may provide more immediate, unrestricted land use, or a less expensive natural attention option, which would most likely require long-term monitoring and restrictions on both land and groundwater use.

Generally, the determination of whether it is probable that a liability has been incurred (i.e., whether the probability criterion is met) is a factual matter. That is, if an environmental site has been identified for remediation and available evidence connects a reporting entity with that site, the probability criterion is generally met. This evidence can be discovered internally (e.g., through environmental studies) or externally (e.g., upon notification from the EPA).

The example below illustrates the application of the probability criterion.

The decision tree below summarizes the FASB’s guidance on determining whether the probability criterion has been met.

The recognition guidance in ASC 410-30-25-7 through 25-13 acknowledges that it is often difficult to estimate the total cost of environmental remediation, particularly in the early stages of the remediation process (e.g., when a reporting entity is named a PRP). However, such difficulty during the estimation process does not preclude recognition of a liability. Rather, a reporting entity must attempt to estimate the cost of the environmental remediation upon determining that the probability criterion is met.

Generally, a point estimate of the total cost to remediate an environmental site will not be determinable in the early stages of the remediation process given the number of external factors typically involved in site cleanup. Rather, total cost will become estimable over time as more information becomes available as a result of performing the required remediation steps. However, ASC 410-30-25-9 acknowledges that “an environmental remediation liability typically is derived by combining estimates of various components of the liability.” For example, the components of the total liability may consist of (1) completion of remedial investigation, (2) completion of a feasibility study, (3) remedial design, (4) the remediation itself, and (5) postremediation monitoring. ASC 410-30-25-11 states that if any one component of the environmental remediation liability is reasonably estimable, that estimate should be used as the minimum in the range of total costs to remediate the site. Therefore, we generally believe that an entity will be able to reasonably estimate the environmental remediation liability (i.e., the estimable criterion will be met) in the early stages of the cleanup process on the basis of the costs of completing a particular component of the liability, which the entity can use to establish a minimum amount. In many cases, a point estimate provided by a specialist or expert may be the best estimate of the remediation liability. Regardless of the determination of the amount representing the best estimate, an entity should thoroughly document key judgments, significant assumptions, and its support for a determination of the recorded amount.

We have observed that reporting entities sometimes delay the recognition of an environmental remediation liability because of certain misconceptions about meeting the estimable criterion. The table below highlights some common misconceptions, along with our interpretive responses to these misconceptions.

The example below illustrates the application of the estimable criterion.

The diagram below illustrates the relationship between the recognition benchmarks outlined above and the probability and reasonably estimable criteria discussed in ASC 410-30-25-4 through 25-13.

The example below illustrates the application of the recognition benchmarks.

The examples in the implementation guidance of ASC 410-30-55, some of which are reproduced below, elaborate on the application of criteria (a) and (b) in ASC 410-30-25-18, which require that the costs incurred result in a future economic benefit.

Conversely, there is limited guidance illustrating the application of criterion (c) in ASC 410-30-25-18, which indicates that environmental costs should be capitalized if the “costs are incurred in preparing for sale that property currently held for sale.” Environmental costs incurred to prepare a property for sale (1) provide a probable future economic benefit to the reporting entity in the form of improved salability and (2) should be capitalized to the extent that they are recoverable.

When determining whether environmental costs associated with property held for sale should be capitalized, an entity must identify the timing of recognition and underlying cause of the costs incurred. For example, the entity would first assess whether the recognition criteria for an environmental remediation liability are met before the property is classified as held for sale. It would generally be inappropriate to capitalize environmental costs while the property is held for sale if such costs should have been recognized before the property was held for sale.

Similarly, costs associated with legal obligations to remediate property are typically not incurred in “preparing for sale” since such obligations exist regardless of whether the property is sold. This concept is supported by the example in ASC 410-30-55-21, which states, in part:

Therefore, we believe that the following types of costs typically qualify for capitalization under ASC 410-30-25-18(c):

• Costs that the reporting entity voluntarily incurred to improve the salability of an asset currently held for sale.
• Costs incurred at the request of a buyer that would otherwise not be a liability of the reporting entity.

The two examples below illustrate the differences between environmental remediation costs that may qualify for capitalization and those that cannot be capitalized.

Regardless of whether the reporting entity develops a cost estimate for completing the entire remediation effort or just a component, the estimate should encompass the total cost of completing such effort or component thereof (i.e., the cost that will ultimately be allocated to all PRPs, as opposed to only the reporting entity’s estimated allocable portion of the cost). As discussed in Section 3.4.2, the reporting entity would then record its allocable share of the environmental remediation liability.

Estimating the costs of completing the total environmental remediation effort or a component thereof involves significant judgment and depends on key assumptions, including:

• The types of costs that should be included in the measurement of the liability.
• The remediation method that is expected to be approved to complete the remediation effort.
• The effects of expected future events and developments.

These assumptions are discussed below.

As a result of the three-step process, the reporting entity’s allocable share of a joint and several liability is equal to (1) the total joint and several environmental remediation liability, less the amount allocable to other PRPs, plus (2) the reporting entity’s share of any amounts that other PRPs are unable to pay.

Since the estimated costs of remediation change on the basis of new information, they are considered changes in estimates under ASC 250 and should be recognized in the period in which they occur.

The typical environmental remediation process spans many years because of the complexity associated with treating the site and monitoring it on a go-forward basis. During this time, environmental laws may change and, as a result, affect the estimated cost of the remediation effort. ASC 410-30 indicates that the measurement of an environmental remediation liability should be based on currently enacted laws and adopted regulations and policies (i.e., future changes in environmental laws should not be anticipated).

In addition, the technology that is used to remediate an environmental site constantly changes throughout the life cycle of the cleanup effort. Changes in available technology often result in lower-than-expected costs to clean up the site. However, ASC 410-30-35-5 states that “[o]nce a methodology has been approved, that methodology and the technology available shall be the basis for estimating the liability until it is probable that there will be formal acceptance of a revised methodology” (emphasis added). Therefore, when measuring an environmental remediation liability, a reporting entity should consider only the technology that is currently available to perform the actions required for the approved remediation method. If and when it becomes probable that a revised method will be approved, the reporting entity should update its cost estimate on the basis of the technology that is currently available for applying that revised method.

With respect to the determination of whether both criteria are met, ASC 410-30-35-12 defines the “amount of the liability or component” as “the reporting entity’s allocable share of the undiscounted joint and several liability.” The guidance also clarifies that the “unit of account” for assessing whether the criteria for discounting are met could be a component of the liability that is reasonably estimable. Accordingly, it is possible for an entity to measure certain components of the liability on a discounted basis and measure other components of the liability on an undiscounted basis.

Because of the nature of environmental liabilities, as well as the long periods over which remediation costs are typically incurred, we generally would not expect the second criterion to be met. That is, it would generally be difficult for reporting entities to reliably determine the amount and timing of cash payments in future periods. Such an assessment should be based on objective and verifiable information.

With respect to the postremediation component of the environmental remediation liability, the costs incurred during this phase generally span a long period, which may or may not be specified by the EPA. Although the absence of a definitive required postremediation monitoring term makes it challenging to determine whether discounting is appropriate, we do not believe that such an absence would preclude discounting. Similarly, the need to estimate any inflation or productivity improvements does not, in itself, result in a conclusion that the cash flows are not reliably determinable. We believe that the AICPA Accounting Standards Executive Committee (the original developer of the guidance codified in ASC 410-30) contemplated situations in which discounting would be acceptable even though the amount or timing of cash payments is not known with certainty or precision. In that regard, on a continuum of probability, the “reliably determinable” standard is something less than “known with certainty or precision” but more than “reasonably estimable.”

The determination that a potential recovery is probable involves significant judgment and should be based on all relevant facts and circumstances. Paragraph C-28 of AICPA Statement of Position 96-1 (the guidance that was codified in ASC 410-30) states, in part:

With respect to the balance sheet, a reporting entity should present a liability for its allocable share of the environmental remediation costs (see Sections 3.4 through 3.4.2.3 for a discussion of how those costs should be measured and allocated). If the reporting entity prepares a classified balance sheet, the environmental remediation liability should be bifurcated into current and noncurrent portions on the basis of the expected timing of settlement.

In addition, as discussed in the guidance above, several assets related to an environmental remediation obligation may be presented in a reporting entity’s balance sheet. These assets should be presented separately from the liability (i.e., they should not be netted against the liability) unless the criteria in ASC 210-20-45-1 (reproduced below) are met.

We believe that with respect to environmental obligations, it would be rare for a reporting entity to conclude that all of the above conditions are met. Specifically, the first criterion contemplates that the asset and liability are with the same counterparty. In the context of environmental obligations, the reporting entity’s liability is typically to the EPA or another state or federal governmental agency, while its assets are recoverable from another entity, such as another PRP or an insurance company. Therefore, it would generally not be appropriate for an entity to offset assets and liabilities related to an environmental remediation obligation in the balance sheet.

With respect to income statement presentation, ASC 410-30-45-4 states that environmental costs should be presented as operating expenses because “the events underlying the incurrence of the obligation relate to an entity’s operations.” In addition, ASC 410-30-45-4 indicates that any credits recorded as a result of probable recoveries should be presented in the same line item as the environmental costs. We believe that when a reporting entity discounts its environmental remediation liability, the expense resulting from accretion of the liability to its undiscounted value should be classified as an additional operating cost of the remediation effort rather than as interest expense. Similarly, we believe that when a reporting entity discounts an asset for probable recoveries, the income resulting from accretion of the asset to its undiscounted value should be classified as operating income rather than interest income.

In addition, an entity should evaluate disclosure requirements related to losses arising after the date of the financial statements. ASC 855-10-50-2 requires an entity to disclose a nonrecognized subsequent event if it is “of such a nature that [it] must be disclosed to keep the financial statements from being misleading.” Although an entity must use judgment to determine whether its financial statements would be misleading without disclosure of a given nonrecognized subsequent event, it would seem prudent for an entity to disclose any reasonably possible nonrecognized loss contingency that could materially affect its financial position, results of operations, or trend of operations. If such disclosure is necessary, it should include both of the following:

• The nature of the contingency (i.e., a description of the environmental remediation obligation). See ASC 450-20-50-9(a).
• An estimate of the possible loss exposure or a statement that such an estimate cannot be made. See ASC 450-20-50-9(b).

For further discussion of disclosure considerations under ASC 450-20 and ASC 275, see Section 2.8.1 of Deloitte’s Roadmap Contingencies, Loss Recoveries, and Guarantees.

That interpretive response also states that in addition to the disclosures required under ASC 410-30 and ASC 450-20, other disclosures may be necessary, including the following:

• “Circumstances affecting the reliability and precision of loss estimates.”
• “The extent to which unasserted claims are reflected in any accrual or may affect the magnitude of the contingency.”
• “Uncertainties with respect to joint and several liability that may affect the magnitude of the contingency, including disclosure of the aggregate expected cost to remediate particular sites that are individually material if the likelihood of contribution by the other significant parties has not been established.”
• “Disclosure of the nature and terms of cost-sharing arrangements with other [PRPs].”
• “The extent to which disclosed but unrecognized contingent losses are expected to be recoverable through insurance, indemnification arrangements, or other sources, with disclosure of any material limitations of that recovery.”
• “Uncertainties regarding the legal sufficiency of insurance claims or solvency of insurance carriers.”
• “The time frame over which the accrued or presently unrecognized amounts may be paid out.”
• “Material components of the accruals and significant assumptions underlying estimates.”

Further, the interpretive response to Question 2 of SAB Topic 5.Y cautions registrants that a disclosure that “the contingency is not expected to be material does not satisfy the requirements of FASB ASC Topic 450 if there is at least a reasonable possibility that a loss exceeding amounts already recognized may have been incurred and the amount of that additional loss would be material to a decision to buy or sell the registrant’s securities. In that case, the registrant must either (a) disclose the estimated additional loss, or range of loss, that is reasonably possible, or (b) state that such an estimate cannot be made.”

In its interpretive response to Question 3 of SAB Topic 5.Y, the SEC staff addresses disclosures that may be required outside the financial statements and states, in part:

SEC Regulation S-K, Item 103, requires disclosure of any material pending legal proceedings, including “the name of the court or agency in which the proceedings are pending, the date instituted, the principal parties thereto, a description of the factual basis alleged to underlie the proceeding and the relief sought.” Similar information is to be included for “any such proceedings known to be contemplated by governmental authorities.”

 

Connecting the Dots

On August 26, 2020, the SEC issued a final rule amending Item 103. The final rule, which became effective on November 9, 2020, permits the use of hyperlinks or cross-references to disclosures about legal proceedings that were included elsewhere in the document provided that the hyperlink or cross-reference does not make reference from such financial statements to other areas outside of the financial statements (e.g., Item 103). The final rule also updates the disclosure threshold for environmental proceedings. Before the amendment, Instruction 5.C to Item 103 required disclosure of an environmental proceeding to which the government was a party if the proceeding was expected to result in sanctions of $100,000 or more. The final rule increases the quantitative threshold to $300,000 but also permits the registrant to elect an alternative higher threshold if the registrant determines that such threshold is more reasonably designed to result in the disclosure of material environmental proceedings. If so, the alternative higher threshold is limited to the lesser of $1 million or 1 percent of the current assets of the registrant and its subsidiaries on a consolidated basis. A registrant must disclose this alternative threshold in each annual and quarterly report.

On September 22, 2021, the SEC’s Division of Corporation Finance publicly released a sample letter that highlights the types of comments it may issue to public companies regarding climate-related disclosures, primarily focusing on disclosures in the business, risk factors, and MD&A sections of filings. The sample comments, which the SEC published before publicly releasing any company-specific comments, serve as an early warning to registrants that have not received any company-specific comments to date. For more information about SEC communications regarding climate-related matters and other environmental, social, and governance (ESG) disclosures, see Deloitte’s September 27, 2021, Heads Up.

On March 21, 2022, the SEC issued a proposed rule that would enhance and standardize the climate-related disclosures provided by public companies. In the proposing release, the SEC noted that certain aspects of the disclosures registrants would be required to provide are similar to those that some companies provide under existing disclosure frameworks and standards, such as those recommended by the Financial Stability Board’s Task Force on Climate-Related Financial Disclosures and the Greenhouse Gas Protocol. For more information about the SEC’s proposed rule on climate-related disclosures, see Deloitte’s March 21, 2022 (updated March 29, 2022); March 29, 2022; and May 26, 2022, Heads Up newsletters.

See Chapter 1 for further discussion about the determination of whether an environmental remediation liability is within the scope of ASC 410-20 or ASC 410-30.

In June 2020, the FASB issued ASU 2020-05, which defers the effective dates of ASC 842 for public not-for-profit entities and private entities. The deferrals apply only if those entities have not yet issued their financial statements (or made their financial statements available for issuance) as of June 3, 2020. For public not-for-profit entities that are eligible for a deferral, ASC 842 is effective for fiscal years beginning after December 15, 2019, and interim periods therein. For private entities that qualify for a deferral, ASC 842 is effective for fiscal years beginning after December 15, 2021, and interim periods within fiscal years beginning after December 15, 2022.

Most public companies have been accounting for leases under the new standard. As of the issuance of this Roadmap, many non-PBEs have already adopted ASC 842. However, some non-PBEs may still be working through the implementation process since their financial statements for fiscal years ended after December 15, 2022, may not have been issued.

When determining the credit adjustment to the risk-free rate, nonpublic entities should use the same sources of information for determining discount rates that they use for mark-to-market calculations or determining the incremental borrowing rates for lease accounting or other purposes. Appropriate sources of this information for nonpublic entities might include financial institutions, other lenders, or comparable public companies.

Entities often incorporate the use of internal resources into their remediation plans. As previously noted, the guidance in ASC 410-20-55-13 requires the amounts included in the ARO cash flow estimate to reflect the costs that a third party would incur to conduct the retirement activities. Therefore, in addition to internal resources, entities need to consider incremental costs (e.g., overhead, equipment charges, profit margin) to ensure that the amounts included in the ARO cash flow estimate reflect the costs that a third party would incur.

Further, estimates for the demolition costs of a long-lived asset may include salvage credits for materials that can be sold. However, it is not appropriate for an entity to include estimated salvage credits when estimating expected cash flows to initially measure an ARO. ASC 410-20 applies only to “retirement” costs. Any estimated salvage value should be considered in connection with the calculation of depreciation of the related long-lived asset. The asset should be depreciated to reduce the net asset value so that it equals the estimated salvage value at the end of the asset’s useful life.

In applying an expected present value technique, entities develop cash flow assumptions on the basis of the various costs that are necessary to achieve the required level of remediation, which will most likely take into consideration several possible outcomes in terms of total remediation costs required. They then multiply those outcomes by assigned probabilities, which reflect the estimated likelihood of occurrence of each potential outcome, to calculate the estimated expected cash flows; the sum of these estimated expected cash flows constitutes the (undiscounted) ARO under an expected present value technique. Entities need to use significant judgment in both estimating costs (cash flows) for various possible outcomes and assigning probabilities to the various outcomes. For a rate-regulated entity (such as a public utility), there may be a single estimate used to calculate the retirement costs that is based on a level of effort agreed to by a governing body, such as a state utility commission or the Federal Energy Regulatory Commission.

When an expected present value technique is used, applying the probability weighting method to several possible cash flow scenarios in the application of an expected present value technique will almost certainly result in differences between actual asset retirement cash flows or their timing and the cash flows or timing incorporated into the initial measurement of an ARO. Further, incorporating third-party and marketplace assumptions into the estimate of ARO cash flows and the initial measurement of the ARO will most likely result in the recognition of gains upon the settlement of the ARO if the entity settles the obligation by using its own resources. These issues are addressed by the guidance in ASC 410-20 on subsequent recognition, subsequent measurement, and derecognition and are further discussed in Sections 4.6.1 through 4.6.3.

The examples below illustrate the subsequent recognition of ARCs as an expense over future periods.

To calculate the accretion expense, an entity multiplies the ARO balance at the beginning of the period by the credit-adjusted risk-free rate that existed when the ARO was initially recognized and, to the extent relevant, the credit-adjusted risk-free rate(s) from subsequent remeasurements. If an ARO is to be adjusted for both the passage of time and a revision of the estimated cash flows, the accretion expense due to the passage of time must be recognized first.

When an entity is unable to identify the appropriate prior period to which downward adjustments of an ARO are related, it would be appropriate for that entity to use a weighted-average credit-adjusted risk-free rate to discount the revised estimated expected cash flows.

There may be situations in which the reduction of an ARO due to a revision of the original estimate of the timing or amount of the obligation exceeds the remaining associated unamortized ARC. In these circumstances, questions may arise about whether the difference should be recorded as a credit to the income statement or as a reduction of the carrying value of the related asset. The accounting will depend on whether the ARC and the related asset are viewed as a single asset or two discrete assets.

ASC 410-20-25-5 states, in part:

ASC 410-20-35-2 states, in part:

ASC 410-20-25-5 appears to support a single-asset approach; however, ASC 410-20-35-2 could be interpreted to support a two-asset approach. If the ARC and related asset are viewed as a single asset, any downward adjustment of an ARO in excess of the related ARC should be recorded as a reduction of the carrying value of the related asset (although we believe that if the downward adjustment of the ARO results in a reduction of the carrying amount of the single asset to below zero, any excess should be recorded as a credit to the income statement). If the two-asset approach is applied, the downward adjustment of an ARO in excess of the ARC cost should be recorded as a credit to the income statement.

As previously noted, since an ARO is required to be initially measured at fair value incorporating marketplace assumptions, differences between estimated future costs used in the measurement of the fair value of an entity’s ARO and actual expenditures incurred by that entity to settle the ARO may occur, resulting in a gain or loss. For example, a gain would most likely result when an entity elects to settle an ARO by using internal resources because the entity’s internal costs are most likely less than the costs reflected in the fair value measurement of the ARO, which would be a function of the costs, profit margin, and market risk premium of a third party.

A gain or loss resulting from settlement of an ARO should be recognized in the period in which the asset retirement activities are performed. When asset retirement activities are performed over more than one reporting period, gains or losses should be recognized pro rata in accordance with the costs incurred during the period as compared with the total costs that the entity expects to incur to settle the ARO.

It would be inappropriate to defer recognition of the entire gain or loss to the period in which the asset retirement activities are completed and the ARO is settled. Doing so would result in overstating or understating the ARO because the amount recognized would not be representative of the amount that the entity would have to pay a third party to assume the costs of settling the ARO.

This approach is supported by paragraph B41 of the Background Information and Basis for Conclusions of FASB Statement 143, which states, in part:

Landfill cells are constructed typically through the excavation of an area, the placement of lower liners consisting of compacted soils and engineered liner materials, and the installation of a leachate collection system. Many industry participants believe that before the placement of waste in a landfill cell, an ARO may exist but only for the cost of removing the installed materials from the cell. These companies believe that the obligating event for the recognition of AROs related to a particular landfill cell at an operating landfill is the placement of waste in that landfill cell, which occurs in relatively small increments over time. As landfill cells are added to the footprint of the landfill and additional waste is placed in these cells, ARO layers may be added to account for the new obligations. The timing and cost associated with the closure or retirement of each new cell may require consideration of variables that are both dependent on and independent of the larger landfill closure schedule.

Once a landfill cell is constructed with its regulation-compliant lower liner, the cell will collect water that must then be managed. If this water has come in contact with waste, it is considered to be leachate, and some level of treatment may be required before a company can dispose of it. An overly large cell may increase the volume of water to be managed. During operation of the landfill, the water or leachate management costs are generally considered to be ongoing maintenance costs in accordance with ASC 410-20-15-3(h) and are not part of an ARO.

Complicating the closure process, slope stabilization and the first layers of the landfill cover can begin when any portion of the landfill cell is filled to final grades. The grading of compacted waste to final slope topography and the placement of an intermediate cover could be regarded as part of the final closure obligation. These early and incremental closure activities complicate the estimation of the retirement obligation for each cell and for the landfill in total. The placement of waste and the daily cover of that waste represent ongoing operational costs, whereas the larger-scale grading and placement of buffer or intermediate cover materials as a part of closure (grading) or to delay the immediate need for closure (intermediate cover) may not be regarded as operational costs. Costs of grading and intermediate cover that are not operational costs should be included in the measurement of the liability for the ARO even though the tasks themselves may occur well in advance of the normal closure activities.

Final closure, which includes the placement of the cap materials, can occur in multiple stages during the life of a landfill and well before the entire landfill or even an entire cell is ready for final closure. Accordingly, the activities and costs underlying the ARO may occur in phases over time and not as a single event at a single point in time. While the total area to be closed and the associated cost may be known and estimable, the staging of the landfill closure affects closure timing, which a company should consider in the expected cash flow scenarios and, therefore, when measuring the fair value of the liability for an ARO.

RCRA Subtitle D requires PCC to be conducted for 30 years, although 40 CFR Section 258.61(b) stipulates that the length of PCC can be adjusted on the basis of site conditions, reduced, or increased on the basis of the demonstration of protectiveness. When measuring an ARO for landfill closure, a company should include PCC as part of the expected cash flows and generally consider a period of 30 years for PCC unless the site-specific permit stipulates otherwise.

Under 40 CFR Section 258.61(a), PCC requires the following:

• “Maintaining the integrity and effectiveness of any final cover, including making repairs to the cover as necessary to correct the effects of settlement, subsidence, erosion, or other events, and preventing run-on and run-off from eroding or otherwise damaging the final cover.”
• “Maintaining and operating the leachate collection system in accordance with the requirements in [40 CFR Section] 258.40, if applicable. The Director of an approved State may allow the owner or operator to stop managing leachate if the owner or operator demonstrates that leachate no longer poses a threat to human health and the environment.”
• “Monitoring the ground water in accordance with the requirements of subpart E of [40 CFR Part 258] and maintaining the ground-water monitoring system, if applicable.”
• “Maintaining and operating the gas monitoring system in accordance with the requirements of [40 CFR Section] 258.23.”

The site-specific permit for a landfill may specify additional terms for PCC that should be considered for each landfill unit. The biological breakdown of waste can result in the formation of landfill gas and the release of leachate, which comes from (1) the moisture in the waste, (2) precipitation into the landfill cell before closure, and (3) the infiltration of precipitation through the final cover. Leachate recovery volumes typically peak in the first few years after closure and decrease to a steady-state volume at some point before PCC is complete. The modeling of leachate generation is commonly used for estimating the annual treatment costs; however, since there may not be sufficient data available in the first few years of PCC for a company to estimate volumes or the decline curve for the remaining PCC period, care should be taken to update ARO cost estimates regularly on the basis of observed volumes. Similarly, the estimation of landfill gas generation is possible and can be extrapolated to allow a company to estimate the operating life of the gas management facilities, and care should therefore be taken to update the cash flow estimates underlying the ARO.

Leachate generation rates should be assessed annually for most landfills, and the leachate treatment costs included in the ARO should be reevaluated. Leachate generation can indicate other landfill closure health issues and can function as a barometer for future costs. Generation that does not decline could indicate issues with landfill cap construction, which may require repair at additional costs. Significant leachate generation may also extend the PCC period required to show stability and no further risk to human health and the environment.

As discussed above, closure for landfill cells may be staged and may not occur as a single event. This staged closure may affect the PCC period since the start of the 30 years of PCC for a cell may differ from the start of the PCC period for other cells or the landfill as a whole. Many state regulators require some type of closure verification to be submitted before they will consider closure to be complete. The acceptance of this closure verification should be used as the basis for beginning the PCC period. When certification of closure is not available, evidence should be sought to validate any assumption that PCC has begun for a particular cell or closure area. Since the groundwater monitoring network encapsulates the entire site and can rarely be isolated to any portion of the landfill, PCC for groundwater monitoring typically does not commence until the complete closure of the landfill. In addition, surface maintenance, security and site access, utilities, and administrative functions are commonly provided at an overall site level and may be required for the full PCC time frame after the final closure at the site.

The type of environmental contamination liability incurred in the normal operation of solid waste facilities, and associated with the retirement of those assets, most likely includes the costs of any site cleanup not specifically included in the operating permit but still required at closure. Examples of such site cleanup are:

• Cleanup, repair, or remediation of infrastructure or access roads and parking areas associated with the landfill.
• Remediation of soil and groundwater affected by a truck washing facility.
• Remediation of equipment maintenance facilities on-site.
• Remediation of storm water management impoundments on-site.

The above examples are remediation activities that are required only as a result of the normal operation of a landfill and only at the time of retirement of all or part of the facility. However, remediation that is required before or after the closure of the site may not be a result of the normal operation of the landfill, as in the following examples:

• Remediation of soil and groundwater affected by accidental discharges and spills on-site.
• Remediation of groundwater affected by a leaking landfill. While an argument could be made that leaks are a normal and expected event arising from historically constructed landfills, an environmental remediation liability may exist when (1) the leakage is beyond what is expected from the normal operation of the landfill and (2) remediation is required before retirement of the asset. For additional discussion, see Chapter 1.

The reclamation of a surface mine is often driven by the need to make the area safe and stable. This is particularly true for highwall mines. Rarely is the complete backfilling of a mine required or feasible. However, backfill and grading may be required to make slopes sustainable, to limit erosion or surface water impacts, and to prevent access. Revegetation and the removal of infrastructure may also be required. The activities common in mine reclamation may be straightforward, but the estimation and maintenance of a mine ARO are anything but. As in the case of landfills, the many variables associated with the timing and extent of reclamation activities could make the initial and subsequent measurement of an ARO challenging.

In a manner similar to the concurrent reclamation of landfills, concurrent reclamation of a mine site may occur. For surface mines, the removal of overburden (soil or rock between the ground surface and the resource extraction area) typically results in a large volume of material to be placed or managed. With concurrent reclamation, when a surface mine is expanded, overburden materials are placed in an area where mining has been completed. This is done to limit mine footprint and to backfill mining areas. A significant benefit of this approach is that it reduces the number of times from excavation to final placement that overburden is moved, thereby reducing or eliminating the need for temporary storage.

Concurrent reclamation at a mine requires accounting consideration. For example, a company must determine when to begin accounting for earthwork as a reclamation activity rather than as operational expense. Some mining companies may conclude that they should account for only the earthwork associated with the final pit footprint and capture the concurrent placement of overburden as an operating expense. Others may include the placement of overburden into the previous excavation as part of an ARO expense.

In a manner similar to the accounting for AROs related to landfills, any final grading and revegetation activities should be included in an ARO related to mining even when those activities are performed concurrently.

The mining method of processing through leaching is commonly used for the extraction of metals such as copper and gold. Leaching at a commercial mine can occupy hundreds of acres, creating both significant retirement obligations and potential environmental remediation liabilities. The leaching of metals through heap leaching involves the loose piling of extracted and crushed ore over a plastic-lined pad area (the “heap leach pad”). The closure of a heap leach pad requires the complete removal of spent ore, berms, pad liners, and all associated plumbing and processing equipment. In addition, if any ponds were created for the processing, these ponds must be drained, with all liquids treated and disposed of and all liners removed.

The removal of liners may result in the identification of soil contamination beneath the heap leach pad due to liner failures. This type of impact could meet the definition of contamination resulting from the normal operation of the asset when treatment is required at retirement and therefore part of the ARO. However, the failure of a berm on a heap leach pad, resulting in the sudden loss of process water and contamination of surrounding soils, could be an example of contamination not associated with normal operation, potentially creating an environmental remediation liability within the scope of ASC 410-30. While the cost of decommissioning and reclaiming an area used for heap leach processing may be estimable since the surface area and decommissioning activities required are known, the cost of any additional remediation may not be estimable before retirement.

In addition to the retirement obligations addressed above, the operation of a mine (particularly, the operation of on-site ore processing) can result in environmental contamination that is not associated with the normal operation and ultimate retirement of the processing facility. For example, consider acid rock drainage, a naturally occurring process in which rocks high in sulfide minerals are disturbed and exposed to rainfall and surface waters. The exposure of the sulfide minerals to air and water can result in the oxidation of the minerals and the formation of a low-pH acidic solution. When this chemical process occurs at a mine, either active or abandoned, it is called acid mine drainage (AMD). At an active mine, operational processes and controls may be in place to control the formation of AMD and to limit the off-site migration or flow of low-pH water. When these processes and controls fail, it is possible for contamination to leave the site, resulting in the need for remediation. Since this type of contamination may not be from the normal operation of the mine or is not associated with the retirement of the asset, the related remediation obligation may not be regarded as an ARO but may need to be treated as an environmental obligation that should be accounted for under ASC 410-30.

The legal obligation associated with the decommissioning of a nuclear power plant arises from the regulations established by the NRC. Before a nuclear power plant begins operations, the NRC requires the licensee to establish or obtain a financial mechanism, such as a trust fund or a guarantee from its parent company, to ensure that there will be sufficient money to cover the cost for the ultimate decommissioning of the facility. The minimum decommissioning funding required by the NRC reflects only the efforts necessary to terminate the NRC license, which is commonly known as the “Part 50 license.”1 This license is not terminated until the licensee has completed all activities included in the approved license termination plan (LTP). Other activities related to facility deactivation and site closure, including operation of the spent fuel storage pool, construction and operation of an independent spent fuel storage installation (ISFSI), demolition of decontaminated structures, and site restoration activities after residual radioactivity has been removed, are not included in the NRC definition of decommissioning. However, costs for the completion of these activities are typically included in the decommissioning cost estimate because there may be a legal obligation imposed by the state or local government, or both, for ultimate release of the property.

Under 10 CFR Section 50.75, each nuclear power plant licensee must report to the NRC every two years the status of its decommissioning fund for each reactor or share of a reactor that it owns. At or about five years before the projected end of operations, each power reactor licensee must submit to the NRC a preliminary decommissioning cost estimate that includes an up-to-date assessment of the major factors that could affect the cost of decommissioning the reactor.

In addition, 10 CFR Section 50.82 requires a nuclear power plant licensee to submit a post-shutdown activities report (PSDAR) to the NRC, as well as a copy to the affected state(s), before or within two years after permanent cessation of operations. The PSDAR must contain the following:

• A description of the planned decommissioning activities.
• A schedule for the accomplishment of significant milestones.
• Documentation that environmental impacts associated with site-specific decommissioning activities have been considered in previously approved environmental impact statements.
• A site-specific decommissioning cost estimate, including the projected cost of managing irradiated fuel.

Under 10 CFR Section 50.82, a nuclear power plant licensee is also required to submit an LTP at least two years before its license is terminated. The LTP must include the following:

• A site characterization.
• Identification of remaining dismantlement activities.
• Plans for site remediation.
• Detailed plans for the final survey of residual contamination at the site.
• A description of the end use of the site, if restricted.
• An updated site-specific estimate of remaining decommissioning costs.
• A supplement to the environmental report.

In general, decommissioning must be completed within 60 years of the plant’s cessation of operations. A time beyond that would be considered only when necessary to protect public health and safety in accordance with NRC regulations. The duration of operations depends on the time prescribed by the operating license. Historically, nuclear facilities have typically been permitted to operate for a period of 60 years based on an initial license of 40 years and a license renewal for an additional 20 years. More recently, some licensees have sought a second license renewal to extend the life of their permitted operating period from 60 years to 80 years. Life extensions affect when a licensed plant is shut down and eventually decommissioned. If a licensee’s application for a life extension is approved, the licensee will need to prepare (1) assumptions about when spent fuel will be removed from the site (i.e., before or after plant shutdown) and (2) a revised decommissioning timeline.

Licensees often change their decommissioning alternative selection during the life of the plant. For example, a licensee that originally anticipated decommissioning a power plant under the DECON alternative may change this decision and select SAFSTOR on the basis of external factors. If the decommissioning alternative is changed, the decommissioning cost estimate must be revised accordingly.

The only way that radioactive waste can become harmless is through decay. However, it can take hundreds of thousands of years for high-level radioactive waste to fully decay. For that reason, high-level radioactive waste must be stored and finally disposed of in a way that provides the public with adequate protection for a very long time.

In 1982, Congress passed the Nuclear Waste Policy Act, assigning the federal government’s long-standing responsibility for disposal of spent nuclear fuel created by commercial nuclear generating plants to the U.S. Department of Energy (DOE). The DOE was to begin accepting spent fuel by January 31, 1998; however, no progress has been made to date in the removal of spent fuel from commercial generating sites. In January 2013, the DOE issued the document Strategy for the Management and Disposal of Used Nuclear Fuel and High-Level Radioactive Waste (the “January 2013 document”). In its January 2013 document, the DOE stated that “[w]ith the appropriate authorizations from Congress, the Administration currently plans to implement a program over the next 10 years that [a]dvances toward the siting and licensing of a larger interim storage facility to be available by 2025 that will have sufficient capacity to provide flexibility in the waste management system and allows for acceptance of enough used nuclear fuel to reduce expected government liabilities.”

Completion of the decommissioning process is dependent on the DOE’s ability to remove spent fuel from the site in a timely manner. As a result of the DOE’s current inability to accept the spent fuel, commercial generating sites have been storing their high-level radioactive waste in the ISFSI, which is typically located on the same property as the nuclear reactor. Costs associated with the long-term storage of the spent fuel are typically included in the decommissioning estimate. Costs for storage include operation and maintenance of the ISFSI and security as required under NRC regulations.

It is important to consider the uncertainties associated with both the requirements related to the storage of spent nuclear fuel and the timing and ultimate disposal of spent fuel, as well as how those uncertainties may affect ARO cost estimates. Three approaches have been observed in industry with respect to the estimation of when the DOE will be able to accept spent fuel from a nuclear power plant:

1. The DOE will not be able to accept spent fuel, and the material will remain on-site indefinitely.
2. The DOE will accept the spent fuel at a later time based on an adjustment to the pickup date provided in the DOE’s July 2004 Acceptance Priority Ranking & Annual Capacity Report, taking into account the 2025 spent fuel pickup start date provided in the DOE’s January 2013 document.
3. An approach similar to that in (2) above, but with a spent fuel pickup start date later than 2025 based on professional judgment.

In addition, many of the commercial generators have entered into settlement agreements with the DOE to obtain reimbursement from the DOE for costs related to spent fuel that were incurred as a result of the DOE’s delay in taking possession of spent fuel. In practice, nuclear power generators have obtained (1) reimbursements from the federal government or state regulatory agencies for operation and maintenance costs or (2) have recovered other monetary damages associated with the federal government’s failure to begin removing spent nuclear fuel and other radioactive waste from former nuclear reactor sites. Reimbursement can be sought through either settlement agreements or damage claims. If a utility has a settlement agreement with the DOE, the utility can seek annual reimbursement for any delay-related nuclear waste storage costs incurred during the year. In the absence of a settlement agreement with the DOE, a utility can file a claim for damages in the U.S. Court of Federal Claims. Unlike settlements, which cover all past and future damages resulting from the DOE’s nuclear waste delays, awards by the U.S. Court of Federal Claims can cover only damages that have already been incurred; accordingly, utilities must continue filing damage claims as they accrue additional delay-related costs.

The NRC is currently developing new regulations that will implement lessons learned from transitioning several plants from operating to decommissioning since 2011. According to an August 2019 report by the NRC’s Office of the Inspector General on the audit of the NRC’s transition process for decommissioning power reactors, the NRC estimates that the new regulations will save licensees, the NRC, and taxpayers approximately $19 million per decommissioning reactor. Issuance of such regulations could potentially be a material triggering event requiring revision of decommissioning cost estimates.

In terms of accounting for MGP liabilities, there is no clear industry consensus on whether the remediation costs should be treated as AROs under ASC 410-20 or as environmental remediation liabilities under ASC 410-30. When it can be clearly shown that the regulatory remediation obligations can be delayed (to a point that they can be reasonably estimated), it may be appropriate to treat the liabilities as AROs. When the regulatory remediation obligations cannot be further delayed, treatment as environmental remediation liabilities may be appropriate.

The cost estimate used to determine the ARO amount is typically referred to as a decommissioning estimate. A decommissioning estimate will include (1) all costs associated with decommissioning the asset and returning the land to its original condition and (2) any proceeds from selling the decommissioned asset at its scrap value. Because of the uncertainty in estimating the value of decommissioned assets, the proceeds component of the decommissioning liability is usually insignificant.

For a solar facility, the main costs associated with decommissioning include those related to the removal of the solar panels, racking, and electrical balance of system assets. Depending on the size and type of the project, there may also be costs associated with the removal of a substation, an operation and maintenance (O&M) building, and on-site access roads. Sometimes, costs associated with the recycling or disposal of solar panels are incurred as a result of the materials used in the panels’ construction, which is described on the EPA’s Web site as follows:

For a wind facility, the main costs associated with decommissioning are those related to the removal of the wind turbine generators (WTGs) and their foundations. Typically, there are also costs associated with the removal of access roads, wiring, substations, and O&M buildings. Most of the materials used to construct wind turbines are relatively easy to recycle, as the American Clean Power Association discusses in a fact sheet:

For a battery facility, the main costs associated with decommissioning are those related to the removal of the battery and battery containers. Depending on the size and type of project, there may also be costs associated with the removal of a substation, an O&M building, and on site access roads. Given the materials used and the type of battery (e.g., lithium-ion, lead, nickel), the appropriate and safest disposal methods must be determined. Often, there are costs associated with the disposal or recycling process.

Most third-party engineering firms can complete a decommissioning estimate, which can be used to determine the amount of the ARO.

The decommissioning estimate is a cost estimate that can change as a result of variations in labor costs, site conditions, and other factors when the actual decommissioning activities occur.

Decommissioning cost estimates often fall within range. As the date of extinguishment of the obligation approaches, the range of cost estimates of the obligation will most likely narrow.

The Association for the Advancement of Cost Engineering International's (AACE's) Recommended Practice 18R-97 delineates a range of accuracy for cost estimates. Since decommissioning cost estimates are site-specific, they fall within Class 4 of the AACE’s Cost Estimate Classification System. Class 4 estimates range from between 15 percent and 30 percent lower than actual cost to between 20 percent and 50 percent higher than actual cost.

Class 4 estimates are generally based on limited information and consequently have fairly wide accuracy ranges. They are typically used for project screening, determination of feasibility, concept evaluation, and preliminary budget approval.

Under IFRS® Accounting Standards, there is no standard that specifically addresses accounting for environmental remediation liabilities. Rather, entities applying IFRS Accounting Standards account for environmental remediation liabilities in accordance with IAS 37. Under IFRS Accounting Standards, IAS 37 is the primary source of guidance on contingencies. For detailed interpretive guidance on IAS 37, see A12 of Deloitte’s iGAAP publication.

There are differences between ASC 450-20 and IAS 37, including, but not limited to, those in the table below.

Under IFRS Accounting Standards, IAS 16 provides guidance on accounting for costs of dismantling and removing an item of property, plant, and equipment and restoring the site on which the item is located when the obligations of dismantlement, removal, and restoration are incurred “either when the item is acquired or as a consequence of having used the item during a particular period for purposes other than to produce inventories during that period.” In addition, IAS 37 (see the table above for a summary of certain guidance in IAS 37, including the standard’s initial recognition guidance) addresses the measurement of decommissioning, restoration, and similar liabilities, and IFRIC Interpretation 1 addresses how to account for changes in existing decommissioning, restoration, and similar liabilities. For detailed interpretive guidance on IAS 16, see A7 of Deloitte’s iGAAP publication.

The table below summarizes the key differences between U.S. GAAP and IFRS Accounting Standards in accounting for obligations associated with the retirement of tangible long-lived assets.