Chapter 5 — Industry Considerations Related to Asset Retirement Obligations and Environmental Obligations

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.