Chapter 5 — Industry Considerations Related to Asset Retirement Obligations and Environmental Obligations
Chapter 5 — Industry Considerations Related to Asset Retirement Obligations and Environmental Obligations
5.1 Introduction
This chapter provides further background and guidance on AROs (and
in some cases, environmental remediation liabilities) commonly encountered by
companies in various industries. Refer to the detailed accounting discussions in
Chapters 3 and 4 for guidance on the initial and subsequent recognition and
measurement of environmental remediation liabilities and AROs.
5.2 Landfill Operation
The design of the modern landfill dates back to the late 1930s, when the first engineered landfill began operation in Fresno, California. Modern landfilling includes the intentional excavation or “berming up” of an area with the intention of containing the waste. Waste is placed, compacted, and covered on a daily basis, and landfill construction includes the use of materials, both natural and man-made, employed to reduce environmental impact.
Beginning in 1976 with the passage of the Resource Conservation and Recovery Act (RCRA), the EPA was tasked with developing and implementing solid waste management standards for landfills with respect to both hazardous and nonhazardous waste streams. Much of RCRA’s subsequent amendments and additional regulations focused on the initial siting, design, and operation of solid waste facilities. RCRA also introduced requirements for closure, postclosure monitoring, and corrective action related to environmental contamination resulting from the landfills. A landfill ARO is based in part on these RCRA closure, postclosure, and corrective action regulations, as discussed previously in Chapter 2.
5.2.1 Landfill Construction
Landfill permits commonly limit the final dimensions of landfills, and landfills typically are constructed in sections called cells. The cells themselves can vary from entire, nearly independent waste areas to overlapping continuations of the cell before (like slices of bread in a loaf). The construction of a landfill using these smaller substructures allows the landfill to be constructed on an as-needed basis, with cells being constructed and finished just before they are needed. In addition to the capital benefit of the staggered construction of demand cells, there are also operational and closure benefits.
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.
5.2.2 Landfill Closure
Closure at a landfill is a complex and multifaceted process since closure obligations can be applied at
both the cell and total landfill level. Further complicating matters, some portions of cell closure can begin
before other portions of the cell have received waste.
Closure consists of four main activities or
design considerations: slope stabilization,
covering (or capping) a landfill, drainage
control, and landfill gas management. Closure
normally begins when a total airspace capacity of
a cell has been consumed and no further waste is
to be placed in the cell. When closure of a cell
or an entire landfill begins, the following
actions take place:
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.
5.2.3 Postclosure Care
At the completion of closure activities, landfill operators are required to conduct postclosure care
(PCC). PCC is necessary because landfills are quite literally living things, or at least made up of a diverse
ecosystem of organisms that slowly break down the waste. In addition to normal settlement resulting
from gravity and the compaction of waste, the biological processes occurring within the landfill can
reduce the volume of waste, resulting in settlement and subsidence.
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.
5.2.4 Contingent Liability at a Solid Waste Facility
As discussed in Chapters 1
and 4,
it is possible that liabilities arising at a solid waste
facility are not within the scope of the guidance in ASC
410-20 on AROs but represent other contingent or
environmental remediation liabilities within the scope of
ASC 450 and ASC 410-30. See Chapter 1 for further discussion
of the scope of ASC 410-20 and ASC 410-30. See also
Deloitte’s Roadmap Contingencies, Loss
Recoveries, and Guarantees for
further discussion of the scope of ASC 450.
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.
5.3 Mining
Mining has occurred in some form since the beginning of civilization, and the methods of extracting
the various commodities have not changed significantly since that time. Mining traditionally requires
excavation either at surface or in the subsurface, with different retirement obligations associated with
each. Solution or in situ leaching is also an extraction method common with soluble minerals and
metals such as uranium, potash, and sodium chloride. While federal mining regulations do exist and are
applicable on federally managed lands, most mining is regulated at the state and local levels. The AROs
associated with mining activities are most commonly created as a result of permit requirements for the
closure and reclamation of a mine at the end of permit life or operations.
The environmental impact and retirement obligations common to mining are divided into two categories
on the basis of the operation of a mine: extraction phase and processing phase. While all mines have an
extraction phase, not all mines will have on-site processing. The retirement obligations between the two
phases are different, and the accounting considerations and common practices are also different.
5.3.1 Extraction Phase
As with most AROs, the specific requirements for retirement are typically
contained in site-specific permits. In a manner similar to that of landfill
permits, permits for mines may only outline the extent of operations and contain
a general reference to a state or federal closure requirement. Commonly, we have
observed that state permits require only that at some point immediately (6–12
months) before ceasing operations, a mine should submit a closure plan. While
this closure plan provides more specifics on the closure, it does not create the
retirement obligation. That is, a retirement obligation exists before a closure
plan is developed, and the ARO is triggered by the excavation and the mine’s
operational activities, the terms of the related permits, and applicable state
and federal statutes. The closure plan provides detail regarding how
specifically the mine will be reclaimed. A mine operator may know the
reclamation methods to be used and have a general understanding and estimate of
the extent of such activities and related costs before it develops a closure
plan.
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.
5.3.2 Processing Phase
After extraction, many minerals and metals require processing so that the
high-value commodities they contain can be concentrated or further extracted.
Processing can include milling, leaching, smelting, concentration and flotation,
and electrowinning. At some mines, ore processing activities occur at the mine
site, and these activities may be included in the mining permit or another
operating permit. In addition to environmental regulations related to the
operation of the processing facility, some operating permits have extensive
retirement obligations.
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.
5.4 Power and Utilities — Nuclear
The U.S. Nuclear Regulatory Commission (NRC) defines decommissioning as permanently removing a nuclear facility from service and reducing
radioactive material on the licensed site to levels that permit termination of the NRC license. Legal
obligations associated with the decommissioning of a nuclear power plant generally are within the scope
of ASC 410-20.
5.4.1 Nuclear Power Plant Decommissioning
Decommissioning involves removing the spent nuclear fuel (i.e., the fuel that has been in the reactor vessel),
dismantling any systems or components containing activated material (such as the reactor vessel and
primary loop), and cleaning up or dismantling contaminated materials from the facility. All activated
materials generally have to be removed from the site and shipped to a waste processing, storage, or
disposal facility.
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.
5.4.2 Nuclear Plant Decommissioning Alternatives
The nuclear decommissioning cost estimate must reflect the type of decommissioning alternative
selected. In accordance with 10 CFR Parts 30, 40, 50, 51, 70, and 72, a nuclear power plant licensee may
choose from three decommissioning alternatives: DECON, SAFSTOR, or ENTOMB. These alternatives are
summarized in the diagram below.
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.
5.4.3 High-Level Radioactive Waste
Highly radioactive byproducts of the reactions that occur inside nuclear reactors are called high-level
radioactive waste. There are two types of high-level radioactive waste: (1) spent fuel when it is accepted
for disposal and (2) waste materials remaining after spent fuel is reprocessed. High-level radioactive
waste must be handled and stored with care because of its highly radioactive fission products.
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:
- The DOE will not be able to accept spent fuel, and the material will remain on-site indefinitely.
- 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.
- 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.
Footnotes
1
The term “Part 50 license” refers to 10 CFR Part 50, the
citation to the corresponding regulations in the Code of Federal
Regulations.
5.5 Power and Utilities — Non-Nuclear
The power and utilities (P&U) industry
includes many technologies for the generation of electricity, and companies in this
industry are likely to have multiple AROs associated with the array of assets
required for the generation and delivery of electricity. Common P&U generation
methods and corresponding potential AROs include the following:
P&U Generation Method
|
Potential ARO
|
---|---|
Coal-fired generation
|
Coal ash impoundments
|
Manufactured gas plants
|
Storage tanks, impoundments, and vaults
|
Solar
|
Solar array and associated structures
|
Wind
|
Turbines
|
In addition, as noted in Chapter
4, the common utility pole used in the distribution of electric power
(and telecommunications) may also be subject to unique disposal requirements,
creating an ARO for the disposal of a utility pole once the pole is extracted and
removed from service.
5.5.1 Coal Ash Impoundments
5.5.1.1 The CCR Rule
The burning of coal results in the generation of coal
combustion residuals commonly called coal ash. Depending on the technology
used to handle air emissions created during the burning of coal, ash is
generated in either a dry or wet form, to be handled either on-site or
off-site. When managed off-site, the ash generated leaves the site without
long-term on-site storage. At facilities where the ash is retained on-site,
impoundments are commonly used to contain the waste material. Coal ash
impoundments, also known as ash landfills, coal ash ponds, and flue gas
disposal ponds, were not universally regulated in the United States until
December 19, 2014. Before that date, the operation and closure of these
impoundments were regulated at the state level if they were regulated at
all. That is, in some states, the management of coal ash was not regulated,
and no obligation related to the handling and retirement of ash impoundments
previously existed. On December 19, 2014, after more than six years of
regulatory development, the EPA released its final rule on regulating the
disposal of coal combustion residuals as solid waste (the “CCR rule”). The
rule was published in the Federal Register on April 17,
2015, and became effective on October 14, 2015.
The CCR rule, while complicated in how it is enforced,
effectively created a single standard for the operation and closure of
impoundments containing coal ash across the United States. In states where
no regulation existed before, the CCR rule created a retirement obligation.
However, in states that previously regulated the closure of these
impoundments, the CCR rule either reinforced or amended the existing state
requirements. As a result, the recognition and measurement of retirement
obligations created by the CCR rule have given rise to diversity and
complexity in practice, particularly for utilities operating in many
states.
While the CCR rule is fairly straightforward, the initial
recognition of an ARO for a long-lived asset that is already well into its
estimated life is more complicated. As previously discussed in Chapter 4, ASC
410-20-25-4 requires an entity to recognize the fair value of an ARO in the
period in which the liability is incurred if a reasonable estimate of the
fair value of the liability can be made. Making a reasonable estimate of the
obligation associated with closing an often old and complex ash impoundment
proved challenging immediately after the CCR rule became law. Estimating the
retirement or closure costs often required the estimation of ash volumes
already within the impoundments, in some situations with very little
information available about the original design or capacity of the
impoundment. Many affected companies initially measured and recorded AROs on
the basis of the best information then available and subsequently refined
their estimates each period as additional information was obtained through
studies and investigations. The initial lack of availability of complete
information generally did not prevent the recognition of some portion of the
liability.
Because of the CCR rule, many entities began accounting for
AROs associated with coal ash impoundments for the first time. Consequently,
the application of the accounting guidance in ASC 410-20 to these AROs
proved challenging. Challenges included, but were not limited to, the
following:
-
Inclusion of operational costs before closure (e.g., groundwater monitoring, maintenance) in the measurement of the ARO.
-
Failure to include long-term PCC activities after closure in the expected cash flows.
-
Estimates using internal cost without proper consideration of fair value concepts (e.g., profit margin, risk premiums).
-
Basic estimates lacking due diligence and consideration of leading industry practices.
Assumptions included in an ARO estimate should be well
supported, and consideration should be given to the expertise of those
persons who develop ARO estimates. Assistance from external subject matter
experts may be required.
Connecting the Dots
Accounting for New AROs
As additional information becomes available,
entities should continually reassess AROs, particularly when
accounting for new AROs created by newly enacted laws or
regulations. Chapter
4 provides additional guidance on the accounting for
changes to an ARO that result from changes in the timing or amount
of expected cash flows. Further, in these circumstances, entities
should ensure that those responsible for the development of asset
retirement/closure cost estimates are familiar with the accounting
guidance, or that there is extensive coordination between
operational personnel, subject matter experts, and
finance/accounting personnel with expertise in the requirements of
ASC 410-20 when developing the cost estimates and other assumptions
that underlie an ARO.
Consistency of ARO Cost
Estimates
A company may be required, in accordance with the
terms of an operating permit or otherwise, to obtain certain forms
of financial assurance associated with an ARO to guarantee the
funding needed to satisfy the ARO in the event of the company’s
insolvency. Under ASC 410-20-35-9, methods of providing assurance
include surety bonds, insurance policies, letters of credit,
guarantees by other entities, and establishment of trust funds or
identification of other assets dedicated to satisfying an ARO.
Obtaining financial assurance typically requires a
company to submit cost estimates associated with satisfying its ARO.
An estimate developed for assurance or insurance purposes may
include or exclude costs that should be excluded from or included in
the measurement of an ARO under ASC 410-20, or it may be based on
assumptions regarding timing or method of settlement that are
inconsistent with the requirements of ASC 410-20. However, a company
should evaluate the consistency of cost estimates made for assurance
or insurance purposes when measuring the fair value of an ARO under
the guidance in ASC 410-20 to understand the reasons for any
significant differences.
5.5.1.2 Recent CCR Developments
For most coal power generators with CCR units, 2018 marked
the completion of background groundwater monitoring, in which companies
gathered data about groundwater in and around their units to determine
concentrations of a select list of chemicals and what would indicate a
statistically significant level (SSL) of excess contamination under federal
cleanup standards.
Recently, there has been an increase in reporting and public
scrutiny of the groundwater data, together with a resulting push on
companies to address the excess contamination. While there is still some
uncertainty regarding state enforcement, the likelihood of some enforcement
action is high. We expect continued public scrutiny and believe that more
states are likely to push for stricter management of CCR implementation.
The federal standards (40 CFR Sections 257.96–98) set forth
an accelerated schedule for the investigation of remedial options and the
implementation of some form of corrective measure. Specifically, within 90
days of identifying an SSL of excess contamination, a company must begin a
corrective measures assessment. Further, within 180 days of completing the
assessment, implementation must begin.
Over the past few years, many instances of excess
contamination have been reported. However, the determination of statistical
significance was largely held off until the completion of background
sampling, which for most companies occurred in 2018.
In May 2022, the EPA and a Colorado utility company reached
an agreement to settle allegations of
noncompliance with CCR regulations. The agreement commits the company to
addressing groundwater contamination issues and ensuring the proper closure
of CCR surface impoundments under RCRA. In addition, the agreement provides
that the company will pay a civil penalty of $925,000. The agreement
demonstrates the EPA’s commitment to working with its state partners to hold
owners and operators of CCR facilities accountable for the damage that has
occurred.
5.5.1.2.1 The Final Closure Part A Rule
On August 28, 2020, the EPA’s final Closure Part A rule was published in the
Federal Register. Effective as of September 28, 2020, the
final Closure Part A rule altered many of the environmental standards
that plants were required to meet to maintain regulatory compliance.
Under this final rule:
- Plant owners were required to initiate closure of unlined CCR impoundments, or impoundments not meeting location restrictions, by April 11, 2021, unless the EPA granted them an extension. Any request for an extension had to be submitted as soon as possible but no later than November 30, 2020.
- Operations under the site-specific alternative closure provision for unlined impoundments were required to cease by October 15, 2023, at the latest.
- Owners and operators of unlined impoundments that meet all location restrictions, comply with the safety factor assessment requirements, and have not detected a statistically significant increase (SSI) above an applicable groundwater protection standard must cease operations by October 15, 2024, at the latest.
- The time frames for the alternative closure provision involving the cessation of coal-fired generation remain the same as those specified by the CCR rule published in the Federal Register on April 17, 2015.
- Unlined impoundments that are 40 acres or smaller were required to stop receiving waste and to complete closure by October 17, 2023, while unlined impoundments larger than 40 acres must do so by October 17, 2028.
The EPA reviewed the 57 demonstrations submitted by
facilities for extensions to the deadline for unlined CCR surface
impoundments to stop receiving waste in accordance with 40 CFR Section
257.103(f)(1) and (f)(2). As of October 15, 2023, the EPA had issued
proposed decisions for seven facilities and was in the process of
reviewing the remaining submitted demonstrations.
5.5.1.2.2 The Final Closure Part B Rule
On November 12, 2020, the EPA’s final Closure Part B rule was
published in the Federal Register. Under this rule, which became
effective on December 14, 2020, a limited number of facilities were
allowed to demonstrate to the EPA or a participating state director
that, on the basis of groundwater data and the design of specific
surface impoundments, they can and will continue to ensure that there is
no reasonable probability of adverse effects on human health and the
environment. The EPA accepted Part B demonstration applications in
accordance with the rule until December 14, 2020 (the application
submission deadline under previous regulations had been November 30,
2020). On January 11, 2022, the EPA determined that seven applications
were complete and that one facility had withdrawn its application.
Another facility withdrew its application in the fall of 2022, leaving a
total of six complete applications awaiting EPA determinations. On
January 25, 2023, the EPA proposed denial determinations on all of those
complete applications.
5.5.1.2.3 Advance Notices of Proposed Rulemaking and Proposed Rule on Legacy CCR Surface Impoundments and CCR Management Units
The EPA issued an advance notice of proposed rulemaking (ANPRM) that
was published in the Federal Register on October 14, 2020. The
ANPRM was released in response to an August 21, 2018, ruling of the U.S.
Court of Appeals for the D.C. Circuit, which vacated and remanded the
EPA’s exemption of inactive impoundments at inactive facilities from the
CCR rule published in the Federal Register on April 17, 2015. In
the ANPRM, the EPA sought comments and data on inactive surface
impoundments at inactive electric utilities, referred to as “legacy CCR
surface impoundments” or “legacy units,” to help the agency develop
future regulations for these CCR units. For example, the EPA
requested:
- “[I]nput on regulatory authority and a potential definition of a legacy CCR surface impoundment.”
- “[S]pecific information on the types of
inactive surface impoundments at inactive facilities that might
be considered legacy CCR surface impoundments,” particularly:
- “[H]ow many of these units might exist.”
- “[T]heir current status (e.g., capped, dry, closed according to state requirements, still holding water).”
- “[N]ames and locations of former power plants that may have these units and when [the plants] closed.”
- “[C]omment on which CCR regulations should apply to legacy CCR surface impoundments and on suggestions for timeframes that EPA should prescribe for coming into compliance with those regulations.”
The original due date for comments was December 14,
2020. However, in a second ANPRM, which was published
in the Federal Register on December 14, 2020, the EPA extended the first
ANPRM’s comment period to February 12, 2021.
Subsequently, in response to the August 21, 2018,
federal appellate court ruling noted above, the EPA issued a
proposed rule that was published in
the Federal Register on May 18, 2023. The proposed rule would
require the safe management of coal ash dumped in areas that are
currently unregulated at the federal level. Such areas include (1)
inactive power plants with surface impoundments that are no longer being
used and (2) historical coal ash disposal areas at power plants with
regulated coal ash units. The proposed rule would apply to historical
contamination and inactive units that no longer support current power
plant operations.
Because legacy CCR surface impoundments are often unlined and
unmonitored, they are more prone to leaks and structural problems than
units at facilities that are currently in service. Consequently, the
proposed rule would provide safeguards for legacy CCR surface
impoundments that are similar to those for inactive impoundments at
active facilities, requiring the proper closure of impoundments and
remediating CCR-contaminated groundwater.
In addition, the proposed rule would address CCR management units
(CCRMUs). As a result of the implementation of the 2015 CCR rule, the
EPA found that power plants with regulated impoundments had also
disposed of coal ash in areas outside of regulated units and that many
utilities had identified those areas as a source of detected groundwater
contamination. Those areas, or CCRMUs, include surface impoundments and
landfills that closed before the effective date of the 2015 CCR rule,
inactive CCR landfills, and other areas where coal ash is placed
directly on the land. The proposed rule would establish groundwater
monitoring, corrective action, closure, and postclosure care
requirements for those areas.
The public comment period for the proposed rule closed on July 17, 2023.
Subject to any revisions made on the basis of comments received, the
provisions in the proposed rule would become effective six months after
publication of a final rule in the Federal Register. Until then,
no facility would be required to meet any of the new requirements. The
EPA has proposed that for both legacy CCR surface impoundments and
CCRMUs, facilities would first need to prepare written reports that
identify the units, delineate the units’ boundaries, include figures of
the facilities and where the units are located, and specify the size of
the units. The facilities would then make these reports publicly
accessible on their Web sites.
The proposed rule’s compliance timeline is outlined in the table
below.
Legacy Impoundments
|
CCRMUs
| |
---|---|---|
Effective date (6 months after finalization
|
|
—
|
3 months after effective date
|
|
Complete facility evaluation report.
|
6 months after effective date
|
|
|
9 months after effective date
|
Prepare:
|
—
|
12 months after effective date
|
|
|
24 months after effective date
|
|
|
Utility companies should start preparing now. They should assess how the
proposed rule would affect their sites by inventorying legacy and CCRMU
sites. In addition, they should consider the timeline to determine when
an accrual should be established and when adjustments should be
made.
5.5.1.2.4 Potential Accounting Impact
All of the recent CCR developments discussed above could
have an accounting impact depending on the recognition of an additional
liability (corrective action), the probability of enforcement, the level
of remedial action required, and whether impoundment closure will even
be required. This year, we expect that in situations in which
contamination above a cleanup level has been identified, companies will
need to consider recognizing costs related to further investigation and
likely remediation.
5.5.2 Manufactured Gas Plants
Manufactured gas plants (MGPs) in the United States date back to the early 19th century and were in
operation as late as the mid-1970s. The manufacturing of synthetic gas was necessary because
of the limited availability of natural gas and the difficulty of transporting it. The chemical process,
while relatively simple, resulted in significant amounts of residual waste. The waste products, which
are persistent, still contaminate many former MGP sites and are the basis for many environmental
remediation liabilities. The contamination from former MGP operations may have continued over
decades, and in many cases, this contamination has remained unremediated. The result is often
contamination spread across a site horizontally, with vertical distribution from near the surface to well
below groundwater and into bedrock.
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.
Footnotes
5.6 Asbestos
Asbestos is a group of naturally occurring minerals with thin fibrous crystals that can be released
when disturbed. Asbestos fibers have been linked to many medical conditions and as a result have
been regulated in some manner for the past 50 years. While regulations in the United States have
not completely banned the use of asbestos, there are various federal and state regulations related to
the disposal of asbestos-containing material (ACM). The regulation of the disposal of ACM results in a
retirement obligation for ACM.
ACM has insulating and strengthening characteristics and is commonly found in building insulation, pipe
wrap, flooring and roofing, and gaskets. It is most often encountered during building demolition and
remodeling or repair. Because many states regulate only the disposal of ACM, the settlement date for
the obligation to address the ACM may be uncertain and will depend on when the asset containing the
ACM is disposed of (which may be subject to significant management discretion).
The examples in the implementation guidance of ASC 410-20-55-57 through 55-62
address the availability of sufficient information and the ability to reasonably
estimate the fair value of an ARO related to the removal and disposal of asbestos.
When ACM is known to exist, a market participant would presumably consider the cost
of addressing the liability in any purchase regardless of settlement date. As with
other AROs, uncertainty of timing should not otherwise prevent the recognition of an
ARO, and the uncertainty should be incorporated in the fair value measurement.
5.7 Oil and Gas
The oil and gas industry is subject to retirement obligations across the entire industry value chain,
from the upstream extraction of hydrocarbons to the downstream processing and ultimately the retail
distribution of refined products. Retirement obligations in the industry include those associated with the
following systems and facilities:
- Upstream:
- Oil wells.
- Saltwater disposal wells.
- Well pads — including tank batteries, ponds, and other improvements.
- Midstream:
- Gathering systems.
- Transmission lines.
- Pressurization systems.
- Downstream:
- Refineries.
- Liquefied natural gas terminals.
- Shipping terminals.
- Retail:
- Underground storage tanks.
- Aboveground storage tanks.
- Offshore:
- Pipelines.
- Platforms.
- Wells.
With the assets above, regulations or lease agreements may require the abandonment in place or
removal of the structure at the end of the useful life of the asset. Some midstream (pipeline) assets
are considered to operate in perpetuity on the basis of the expectation of repair and maintenance
rather than removal and retirement. On the retail side, underground storage tanks must be removed,
and some level of soil remediation is often required as a result of unintentional leaks. Because
of complexities of working offshore along with increased regulatory scrutiny, the cost of offshore
decommissioning is often significantly higher than that of similar onshore activities.
5.8 Renewables
In the case of renewable energy, AROs are most often associated with a land
lease. When an entity is leasing land from a landowner, the landowner often
requests an agreement that the land will be returned to its original condition
at the end of the lease. In addition, AROs can be required by certain towns or
other municipalities to meet permitting or other requirements for construction
and installation of the asset.
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:
Crystalline-silicon
solar technology represents most of the solar panel market share. This type
of panel is constructed with an aluminum frame, glass, copper wire, polymer
layers and a backsheet, silicon solar cells, and a plastic junction box. The
polymer layers seal the panel from exposure to weather but can make
recycling and panel disassembling difficult, as high temperatures are often
required to loosen the adhesive.
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:
Wind
turbines are made up of many materials that have substantial salvage value
at the end of its operational life and are recyclable. In fact, 80–94% of a
wind turbine’s mass consists of easily recycled materials, such as
steel/iron (approximately 88% of a turbine’s mass), aluminum (approximately
0.7%), and copper (approximately 2.7%). Other wind turbine components such
as blades, nacelle covers and rotor covers are made [up of] composite
materials, mostly fiberglass and carbon fiber, which, while non-toxic and
safe, are more difficult to process for other purposes. However, these
components make up roughly only 8% of a wind turbine’s total mass.
[Footnotes omitted]
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.