HomeMy WebLinkAbout6/11/2024 - Energy Right - Decommissioning Utility-Scale Solar Facilities - Weldon Cooper Center @ UVA - August 2022Dec om missioning
Utility-Scale Solar
Facilities
Financial Best Practices for
Virginia Localities
AUGUST 2022
Irene Cox
How can Virginia localities hosting utility-scale solar projects minimize their risk of bearing decommissioning obligations without increasing barriers to such projects?
This report seeks to offer a practical inventory of
regulatory options which localities can adjust based
on a utility-scale solar project’s characteristics. The
author analyzes decommissioning best practices
with respect to context-appropriate site removal
and land restoration regulations, legal protections
for the locality, financial assurance mechanisms
and posting methods, and adjustments to
decommissioning security which account for
inflation, any administrative factor, and salvage
credit. Decommissioning regulations required by
state law are distinguished from those which a
locality may enforce at its discretion.
ABOUT THE AUTHOR
Irene Cox is a policy intern at the Weldon Cooper Center for Public Service and a
Master of Public Policy candidate at the University of Virginia’s Frank Batten School
of Leadership and Public Policy. She holds a B.A. in Economics from the University
of Virginia and hopes to continue evaluating policy options which promote renewable
energy infrastructure in the Commonwealth of Virginia. Irene can be reached by
email at ivc6vq@virginia.edu.
ACKNOWLEDGEMENTS
I would like to express my sincere gratitude to Elizabeth Marshall and Professor
Bill Shobe for their guidance and support on this project. I also thank the local
representatives, solar developers, policy consultants, and field experts whose kind
consideration and helpful perspectives were instrumental in establishing the context
for this paper. Any errors found in this report are the author’s alone.
This report was prepared by Irene Cox for the Energy Transition Initiative,
which is housed in the Center for Economic and Policy Studies at the
University of Virginia Weldon Cooper Center for Public Service.
TABLE OF CONTENTS
ABBREVIATIONS ............................................................................................................................................... 1
EXECUTIVE SUMMARY .................................................................................................................................... 2
Decommissioning Ordinances ............................................................................................................... 3
Legal Framework in Case of Abandonment ........................................................................................... 3
Financial Assurance .............................................................................................................................. 3
Salvage Credit ...................................................................................................................................... 4
PROBLEM STATEMENT ................................................................................................................................... 5
BACKGROUND .................................................................................................................................................. 6
What is a Utility-Scale Solar Facility? .................................................................................................... 6
Economic Context ................................................................................................................................ 6
Summary of State Laws Indicating Mandatory and Discretionary Local Actions upon Utility-Scale Solar
Facilities.............................................................................................................................................................. 11
DECOMMISSIONING ORDINANCE ............................................................................................................ 14
Where to State Decommissioning Requirements ................................................................................. 14
Refurbishment and Repowering ......................................................................................................... 14
Recommended Decommissioning Ordinance Content ......................................................................... 16
Procedure ........................................................................................................................................................... 16
Terms and Conditions ........................................................................................................................................ 17
Land Management and Restoration .................................................................................................................. 18
Decommissioning Plan ....................................................................................................................................... 19
LEGAL FRAMEWORK FOR LOCALITY IN CASE OF ABANDONMENT................................................ 22
Abandonment and Removal Clause .................................................................................................... 22
Special Permit Application .................................................................................................................. 23
Temporary Variance Process .............................................................................................................. 23
Examples ........................................................................................................................................... 23
FINANCIAL ASSURANCE ............................................................................................................................. 26
What Kinds of Financial Assurance Should a Locality Allow? ................................................................ 27
Trust Funds ......................................................................................................................................................... 27
Cash Escrow ....................................................................................................................................................... 27
Letter of Credit ................................................................................................................................................... 28
Surety Bond Guaranteeing Payment or Performance ....................................................................................... 29
Insurance ............................................................................................................................................................ 30
Guarantee by an Investment-Grade Entity ........................................................................................................ 31
Additional Considerations .................................................................................................................................. 34
Summary of Financial Assurance Mechanisms .................................................................................................. 36
When Should a Locality Require an Owner or Affiliate to Post FA? ....................................................... 38
DETERMINING DECOMMISSIONING COSTS .......................................................................................... 41
Valuation of the Administrative Factor ............................................................................................... 41
Salvage Credit .................................................................................................................................... 42
Salvage Plan ....................................................................................................................................................... 42
When To Allow a Salvage Credit ........................................................................................................................ 42
Salvage Credit Calculations ................................................................................................................................ 43
SUMMARY OF RECOMMENDATIONS ...................................................................................................... 44
APPENDIX A: DECOMMISSIONING REGULATIONS BY VIRGINIA LOCALITY, AS OF JULY 2022
........................................................................................................................................................................... 47
APPENDIX B: DECOMMISSIONING CONSIDERATIONS ...................................................................... 49
REFERENCES ................................................................................................................................................... 52
Decommissioning Utility-Scale Solar Facilities 1
ABBREVIATIONS
AEP:
ApCo: Appalachian Power Company
BLS: Bureau of Labor Statistics
CPCN: Certificate of Public Convenience
and Necessity
DEQ: Virginia Department of Environmental
Quality
EoL: End-of-Life
EPA: U.S. Environmental Protection Agency
FA: Financial Assurance
kWh: Kilowatt hours
LC: Letter of Credit
MW: Megawatt
NRCS: Natural Resources Conservation
Service
NREL: National Renewable Energy
Laboratory
NRSRO: Nationally Recognized Statistical
Ratings Organization
NYSERDA: New York State Energy Research
and Development Authority
PBR:
PJM:
abbreviates Pennsylvania, New Jersey, and
Maryland, the initial territories whose utilities
joined together into an RTO. PJM now
operates in all or parts of Delaware, Ohio,
Virginia, Kentucky, North Carolina, West
Virginia, Indiana, Michigan, and Illinois.
PPA: Power Purchase Agreement
PPI: Producer Price Index
PV: Photovoltaic
RCRA: Resource Conservation and Recovery
Act of 1976
RPS: Renewable Energy Portfolio Standard
RTO: Regional Transmission Organization
SCC: State Corporation Commission
SEC: U.S. Securities and Exchange
Commission
SEIA: Solar Energy Industries Association
USDA: United States Department of
Agriculture
TCLP: Toxicity Characteristic Leaching
Protocol
VCEA: Virginia Clean Economy Act
Decommissioning Utility-Scale Solar Facilities 2
EXECUTIVE SUMMARY
When any large energy generation facility reaches the end of its project life, it is commonly
decommissioned in accordance with local, state, and federal guidelines: The facility owner disposes
of site infrastructure and restores the facility’s real property to a condition suitable for its subsequent
use. As is the case with other energy facilities, localities appropriately request specific
decommissioning plans and financial assurance from the owners of utility-scale solar facilities in
advance of decommissioning. While the financial assurance amounts appropriate for utility-scale
solar projects can be quite large—hundreds of thousands of dollars or more—utility-scale solar
decommissioning is relatively less expensive, time-intensive, and environmentally disruptive than is
the case for decommissioning end-of-life (EoL) nuclear, coal, natural gas, and oil well facilities.
To date, it can be challenging for Virginia localities to access contextualized guidance for creating
decommissioning policies which both minimize the locality’s exposure to the risk of bearing
decommissioning obligations and avoid imposing excessive or superfluous costs on the developers
and owners of utility-scale solar projects.
Because the Code of Virginia establishes a hybrid regulatory structure for solar energy, localities have
the authority to regulate the siting and decommissioning processes for solar facilities beyond the
requirements of state law and the responsibility to enforce both state and local solar ordinances (Va.
Stat. §15.2-2241.2, 2019; Va. Stat. §§15.2-2288.7:2288.8, 2021; Va. Stat. §§15.2-2316.7:2316.9, 2021).
While the local regulations governing utility-scale solar sites vary, a locality-approved plan for
decommissioning an end-of-life plant and restoring the facility site is often required for construction
to begin. By developing and applying comprehensive, context-appropriate strategies for
decommissioning end-of-life (EoL) large- and utility-scale solar projects, localities can ensure that
land is left in usable condition at the end of a solar facility’s useful life.
This analysis evaluates several local policy strategies for managing utility-scale solar
decommissioning in the Commonwealth of Virginia:
1) Establishing an effective decommissioning ordinance;
2) Defining a legal framework to enforce decommissioning;
3) Requesting appropriate forms of financial assurance; and
4) Factoring salvage credit, inflation, and administrative costs.
This paper distinguishes among (i) the decommissioning regulations a locality must enforce, as
required by state law, (ii) those which the county or city has the authority to enforce at its discretion,
and (iii) discretionary regulations which are recommended as best practice for the locality. An
overview of the topics and recommendations of this paper is provided below.
Decommissioning Utility-Scale Solar Facilities 3
DECOMMISSIONING ORDINANCES
A decommissioning ordinance states the minimum decommissioning requirements to be executed
by a solar facility’s owner at the end of the project’s life or upon abandonment, and the appropriate
contents for a decommissioning plan that a developer should file with the locality prior to initiating
site construction. The requirements of a decommissioning ordinance may be formally incorporated
into a locality’s existing zoning ordinance, solar ordinance, or other municipal code. If no local law
specifies minimum decommissioning requirements, then a locality may instead issue site-specific
decommissioning requirements as a component of a conditional use permit, special use permit,
siting agreement, or special exception. A locality with laws regulating decommissioning may also
create a site-specific decommissioning ordinance with stricter or additional provisions. Virginia
localities commonly include decommissioning provisions as a component of their solar ordinance,
and these provisions apply to large- and utility-scale solar projects. Localities also have the authority
to adopt a decommissioning ordinance independently of adopting a solar ordinance.
A locality’s decommissioning ordinance should define key terms, such as decommissioning and
abandonment; specify financial assurance requirements, salvage allowances, and the processes for
accurately adjusting costs due to annual inflation and changes in secondary markets for solar
materials; and state the conditions for sediment and erosion control compliance, post-closure land-
use, and land restoration. Localities may also consider suggesting the minimum conditions a facility’s
owner or affiliate should fulfill if they seek to extend the life of the facility by installing new solar
panels, a process known as repowering.
LEGAL FRAMEWORK IN CASE OF ABANDONMENT
Localities may protect themselves against bearing decommissioning costs by stating the conditions
which affect access to financial assurance. These methods include defining facility non-performance
and abandonment, stating the point at which financial assurance instruments are activated, requiring
a special permit application in which the decommissioning plan is codified in the locality’s zoning
ordinance, issuing site approvals or permits with an abandonment and removal clause, and
specifying a temporary variance.
FINANCIAL ASSURANCE
Localities may access a menu of financial assurance (FA) options that cover the full cost of
decommissioning. Different forms of FA are appropriate in different circumstances. Common FA
mechanisms include but are not limited to:
trust funds,
cash escrow,
irrevocable letters of credit,
Decommissioning Utility-Scale Solar Facilities 4
surety bonds guaranteeing payment or performance,
insurance,
financial tests, and
guarantees by an investment-grade entity, such as a parent guarantee or promissory letter.
It is in both the locality’s and the developer’s best interest to minimize the costs associated with
posting security. The type of FA a locality should require of a developer and the time or times at
which it should be posted are context dependent. The surety amount available to the locality should
be periodically adjusted based on a Virginia-licensed engineer’s re-evaluation of decommissioning
costs. Although the appropriate timeframe for posting decommissioning security may vary by solar
project, a locality should in every case require the site owner to post FA until the decommissioning
process has been completed.
SALVAGE CREDIT
It is at the locality’s discretion whether to allow a salvage credit. While state law does not require the
inclusion of a salvage credit against decommissioning costs, it is good practice for a locality to allow
a salvage credit for the portion of solar hardware that can be resold for scrap value or reuse at the
end of a facility’s operating life. A salvage credit need not equal the total estimated salvage value. A
locality can protect against fluctuations in salvage value by using a salvage credit calculation which
includes a reserve value.
Decommissioning Utility-Scale Solar Facilities 5
PROBLEM STATEMENT
A utility-scale solar facility, once built, is very likely to remain economically productive for a long
period of time. A solar panel can remain in service for 30 years or longer. An owner or operator of a
grid-connected solar facility is unlikely to abandon a utility-scale project during its expected lifetime
because of the high value of power produced and contractual obligations arising from the project’s
long-term economic value (North Carolina DEQ, 2022, p. 4). Even as the initially installed panels age,
project owners will very often face a strong incentive to install new panels on the existing site, a
process known as repowering. But any industrial facility can reach an end to its useful economic life,
so it is in the locality’s interest to establish clear decommissioning conditions so that (i) should a
project owner become financially insolvent, the locality does not incur the responsibility of
decommissioning the solar project, and (ii) at the end of a project’s life, retired equipment is
responsibly managed and the land is appropriately restored, prepared for redevelopment, or
equipped for repowering.
Utility-scale solar development will likely continue to increase as the Commonwealth as Virginia is
forecast to face higher energy demands over the next decade (PJM, 2022; Shobe, 2021), as Dominion
Energy and Appalachian Electric Power continue to comply with the Virginia Clean Economy Act
(Duimstra, 2021), and as the costs of solar generation continue to fall (Basore & Feldman, 2022; Davis
et al., 2021; McGowan, 2021; U.S. EIA, 2020). Host localities will benefit from timely access to an
inventory of guiding practices in anticipation of these facilities’ eventual decommissioning.
The practices detailed in this paper seek to help localities protect against the risk of bearing
decommissioning costs while simultaneously reducing developers’ barriers to installing utility-scale
solar projects.
Decommissioning Utility-Scale Solar Facilities 6
BACKGROUND
WHAT IS A UTILITY-SCALE SOLAR FACILITY?
For the purposes of this report, a utility-scale solar facility is any ground-mounted solar photovoltaic
(PV) project with the nameplate capacity to generate five or more megawatts (MW) of electricity—as
measured in alternating current—then injected to the grid for offsite consumption, in accordance
with the threshold set by the National Renewable Energy Laboratory (NREL, 2022). The term large-
scale solar facility refers to installations with a capacity of at least one MW; utility-scale facilities are
by definition large-scale solar plants.1
Something less than ten acres of land are required for each MW of solar capacity: One somewhat
dated study estimates a capacity-weighted average ranging from 7.3 acres per MW (direct land-use)
to 8.9 acres per MW (total land area) (Ong et al., 2013). This land footprint has likely fallen as more
efficient solar panels have become available. Solar cell efficiency has increased from 18% in 2015 to
over 22% in 2021. The Solar Energy Industries Association currently reports a range of between 5 and
10 acres per MW, depending on specific site characteristics. The total number of solar PV panels
installed per acre is site-specific, varying with terrain, hardware characteristics (e.g., tracking versus
mounted panels), and setup decisions (e.g., spacing between arrays, angled versus flat configuration).
Back-of-the-envelope calculations based on publicly accessible data from the North Carolina DEQ
suggest that, depending on solar technology and site conditions, roughly 2,500 to 5,050 solar panels
are required to produce one MW of electricity (Scott, 2022).
Utility-scale solar facilities average a project life of thirty years, after which point installed solar PV
panels produce electricity at approximately eighty to eighty-five percent of their rated capacity
(Curtis, Buchanan, Smith, & Heath, 2021; Atasu, Duran, & Wassenhove, 2021). The increasing
efficiency of solar technology (Basore & Feldman, 2022) offers both a lengthened project life in the
future (Curtis et al., 2021) and the opportunity to repower existing utility-scale projects with more
efficient, higher output panels. (MDOC, 2018, p. 4).
ECONOMIC CONTEXT
Researchers project that over the next two decades, solar energy systems will drive at least fifteen
percent of the forecasted 5.9 trillion kWh global increase in new electricity generation from
renewable energy sources (Eissa & Tian, 2017). The levelized cost of photovoltaic energy is further
predicted to decrease through at least 2030, indicating the potential for lower energy costs and
1 Author’s Note: The U.S. Energy Information Administration (EIA, 2019), the Solar Energy Industries Association (SEIA, 2022), and many local ordinances define “utility-scale solar” as PV capacity greater than 1 MW. This paper applies a 5 MW threshold for utility-scale solar and a 1 MW threshold for large-scale solar for internal consistency.
Decommissioning Utility-Scale Solar Facilities 7
higher investment returns (Creutzig et al., 2017). For the first five months of 2022, utility-scale solar
accounted for more than five percent of Virginia’s in-state electricity generation. Solar generation in
Virginia more than tripled between 2019 and 2021 (EIA, 2022), and has continued to grow rapidly:
Virginia was the fifth-leading state in the country for newly installed solar capacity in 2020
(McGowan, 2021; Vogelsong, 2021) and ranked fourth in 2021 (SEIA, 2022). A June 2022 analysis by
the Solar Energy Industries Association (SEIA) estimates that solar developers have invested $4.2
billion in the Commonwealth to date, with more than 35% of that activity occurring in 2021 alone.
The benefits of these investments in carbon-free solar development will continue accruing to
localities over time as they receive tax revenues from operational utility-scale solar facilities.
As of July 2022, federal data indicated that at least 63 large-scale solar facilities operated in Virginia.
Of these, 55 facilities had a rated capacity of five MW or greater—a 44.7% increase in operating
utility-scale solar facilities from January 2021 (EIA, 2022; Berryhill, 2021). PJM, EIA, and DEQ data
indicate that at least twenty additional utility-scale projects have received a PBR and are planned for
installation, under construction, or active but not yet producing power as of July 2022, with many
other proposals engaged in local permitting and PBR review processes.
Decommissioning Utility-Scale Solar Facilities 8
Figure 1 – Operational Utility-Scale Solar Facilities in the Commonwealth of Virginia, as of July 2022 2
Facility Name MW Locality Date Facility Name MW Locality Date
Eastern Shore Solar,
LLC 80 Accomack 2016 Desper / Belcher Solar 88.2 Louisa 2021
Depot Solar 15 Campbell 2022 20 Northampton 2017
Skipjack Solar 175 2022 TPE Kentuck Solar LLC 6 Pittsylvania 2018
13.8 Charlotte 2020 50 Pittsylvania 2021
32 Chesapeake 2020 Danville Farm, LLC 12 Pittsylvania 2020
Bedford Solar Center 70 Chesapeake 2021 10 Pittsylvania 2020
10 Clarke 2017 Scott-II Solar LLC 20 Powhatan 2017
LLC 20 Essex 2017 Road LLC 19.7 Prince George 2020
20 Fauquier 2017 Fort Powhatan Solar 150 Prince George 2022
Palmer Solar Center 5 Fluvanna 2017 LLC 15.7 Shenandoah 2021
Gloucester Solar, LLC 19.9 Gloucester 2019 LLC 100 Southampton 2017
Sadler Solar 100 Greensville 2021 15 Suffolk 2020
80 Greensville 2020 Colonial Trail West Surry 2019
80 Halifax 2021 Spring Grove I 97.9 Surry 2020
25 Hanover 2020 Sussex Drive, LLC 20 Sussex 2017
2 Author’s Note: The most recent U.S. EIA Monthly Electric Generator Inventory can be located at the following link:
https://www.eia.gov/electricity/data/eia860m/
Decommissioning Utility-Scale Solar Facilities 9
Facility Name MW Locality Date Facility Name MW Locality Date
Briel Farm Solar 20 Henrico 2021 Oceana Solar 17.6 Virginia Beach 2017
Energix Leatherwood,
LLC 20 Henry 2021 19.9 Westmoreland 2021
Rochambeau Solar 19.9 County 2021 Gardy's Mill Solar 14 Westmoreland 2020
Farm 20 Louisa 2016
Source: U.S. EIA Monthly Electric Generator Inventory, PJM Interconnection Queue, Virginia DEQ
The median nameplate capacity for Virginia’s active utility-scale solar projects is 20.0 MW. Most of
Virginia’s operating large-scale solar facilities are in the twelve to fifty MW range, with three out of
every four facilities generating twenty-five or fewer megawatts of electricity. Solar projects that are
“extremely” large by comparison are at times approved in phases: Spotsylvania Solar, for example,
comprises four land parcels with separate project names and SCC Certificate Numbers. Hollyfield I
and II, Buckingham I and II, and Scott I and II, respectively, fall in the thirteen to twenty MW range.
Phased approvals for large projects are not necessarily the precedent: Some large facilities, such as
the 800 MW Randolph Solar Project, have been approved under a single application.
Figure 2 – Large-Scale Solar Capacity by Operating Year, as of July 20223
Year in
Service < 2MW < 5 MW < 20 MW < 50 MW < 70 MW < 100 MW greater Total
1 1 2 1 1 6
3 5 6 1 15
3 1 4
1 1 1 3
1 7 2 3 1 14
1 4 5 1 4 1 16
1 2 2 4
Total 3 5 23 17 1 8 6 63
Source: U.S. EIA Monthly Electric Generator Inventory
3 Author’s Note: Due to the lack of state and federal data, the total number of large-scale solar facilities may be an undercount.
Figures 1 and 2 synthesize the most reliable EIA, PJM, and DEQ data available to date.
Decommissioning Utility-Scale Solar Facilities 10
REGULATORY FRAMEWORK
The Virginia Clean Economy Act (VCEA) of 2020 created a mandatory renewable energy portfolio
standard (RPS) under which the Commonwealth’s two publicly regulated utilities, Appalachian Power
Company (ApCo)—a subsidiary of American Electric Power (AEP)—and Dominion Energy, shall
produce electricity solely from non-carbon-emitting sources by 2050 and 2045, respectively. One key
component of the VCEA establishes a goal of 16.1 gigawatts of electricity generation capacity by
solar or onshore wind facilities, of which 35% must be provided by third-party power producers in
the form of power purchase agreements (PPAs) (Va. Stat. §56-585.5, 2020). To satisfy this capacity
target, Dominion Energy and AEP may enter into PPAs and buy renewable energy from a third party
operating a solar or wind facility, develop new solar facilities subject to the approval of the State
Corporation Commission (SCC), or acquire solar facilities that are operational or under construction
from other developers. Before constructing a new solar facility, publicly regulated utilities must
obtain a Certificate of Public Convenience and Necessity (CPCN) from the SCC (Va. Stat. §56-265.2,
2017). The state’s forecasted energy needs are sufficiently high (Shobe, 2021; PJM, 2022) and its solar
industry sufficiently cost effective (Bruggers, 2021) that developers would likely continue to propose
and build utility-scale solar facilities at a rapid pace even in the absence of the VCEA targets.
Before developers can construct a utility-scale solar project with a capacity between 5 and 150 MW,
they must receive a permit by rule (PBR) from the DEQ or, depending on a publicly regulated utility’s
involvement and the developers’ own preferences, they may instead file for an SCC permit (20VAC5-
302-20). Developers’ PBR applications must include an air quality analysis, assessments of cultural,
wildlife, and natural heritage resources, a site and context map, a public comment period, and a
certification of local government approval (9VAC-15-60-30:120). Solar energy sites with a capacity
less than five MW and occupying between two and ten acres undergo a less intensive approval
process known as “Section 130” (9VAC-15-60-130).
The Code of Virginia governs utility-scale solar PV system siting and decommissioning through
multiple provisions, chiefly Sections 15.2-2316.6:2316.9, 15.2-2232, 15.2-2241.2, and 15.2-
2288.7:2288.8. Sections 15.2-2316.6:2316.9 of the Code of Virginia authorize localities to enter into
siting agreements for solar facilities with a capacity greater than five MW and describe the required
procedure for negotiating and signing such agreements. Section 15.2-2232 describes the contexts in
which a locality must deem a proposed solar facility substantially in accord with its comprehensive
plan. Section 15.2-2241.2 defines “decommissioning” and states the minimum requirements of a
written decommissioning agreement into which a solar facility’s owner, land-lessee, or land-
developer must enter with the locality. Sections 15.2-2288.7:2288.8 outline zoning permissions and
special exception requirements for roof-mounted and ground-mounted solar development.
Virginia House Bill 206 (2022) establishes land management measures for solar facilities on forested
lands and USDA-designated prime agricultural soils. HB 206 will affect the future siting of utility-scale
solar projects (Holmes, 2022; Lerch, 2022). It remains unclear whether HB 206 will have
decommissioning implications for solar energy projects for which an interconnection request is not
Decommissioning Utility-Scale Solar Facilities 11
received by December 31, 2024 (Va. Stat. § 10.1-1197.6; Weaver, 2022). As of August 2022,
regulations pursuant to HB 206 remain under development.
Summary of State Laws Indicating Mandatory and Discretionary Local Actions upon Utility-Scale
Solar Facilities
A locality must:
Receive a written notice from a prospective solar developer that discloses their intentions to site
a facility with a capacity greater than 5 MW within the locality (Va. Stat. §15.2.-2316.7).
Either as part of its local legislative approval process or as a condition of approving a site plan,
require the owner, lessee, or developer of the land on which a solar facility would be constructed
to enter into a written agreement to decommission solar energy equipment, facilities, and
devices. This written agreement must include the following terms (Va. Stat. §15.2.-2241.2):
If the party that enters into such written agreement with the locality defaults in its
decommissioning obligation, the locality has the right to enter the real property of the record
title owner of such property without further consent of such owner and to engage in
decommissioning.
Such owner, lessee, or developer must provide financial assurance of such performance to
the locality in the form of certified funds, cash escrow, bond, letter of credit, or parent
guarantee, based upon an estimate of a professional engineer licensed in the
Commonwealth, who is engaged by the applicant, with experience in preparing
decommissioning estimates and approved by the locality.
The locality cannot enforce a decommissioning cost estimate in excess of the projected cost
of decommissioning calculated by a Virginia-licensed engineer.
Observe the Commonwealth’s minimum definition of “decommission”: “The removal and proper
disposal of solar energy equipment, facilities, or devices on real property that has been deemed
by the locality to be subject to §15.2.-2232 and therefore subject to [§15.2.-2241.2].
“Decommission” includes the reasonable restoration of the real property upon which such solar
equipment, facilities, or devices are located, including (i) soil stabilization and (ii) revegetation of
the ground cover of the real property disturbed by the installation of such equipment, facilities,
or devices” (Va. Stat. §15.2.-2241.2).
Formally approve any negotiated siting agreement for a solar project via a majority of a quorum
vote among the local governing body. A locality does not have to negotiate a siting agreement
in order to approve a solar project (Va. Stat. §15.2.-2316.7).
Decommissioning Utility-Scale Solar Facilities 12
If the locality proceeds with a siting agreement, it must:
Schedule a public hearing once the locality’s governing body and the facility applicant agree
on the terms and conditions of the siting agreement, prior to voting to approve the siting
agreement (Va. Stat. §15.2.-2316.8).
Enforce the signed siting agreement (Va. Stat. §15.2.-2316.8) and its existing ordinances and
regulations, to the extent that they are not inconsistent with the siting agreement’s terms
and conditions (Va. Stat. §15.2.-2316.9).
Recognize that by signing a siting agreement, the locality deems the solar project
substantially in accord with its comprehensive plan (Va. Stat. §15.2.-2316.9).
If the locality chooses to create a local ordinance addressing the siting of solar facilities that
generate electricity, the solar ordinance must:
Be consistent with the provisions of the Commonwealth Clean Energy Policy (Va. Stat. § 45.2-1708).
Provide reasonable criteria to be addressed in the siting of the facility. These criteria shall provide for the locality’s protection in a manner consistent with the Commonwealth’s goals to promote the generation of energy from solar and wind resources (Va. Stat. § 45.2-1708).
Include provisions establishing reasonable siting requirements, and must include provisions
limiting noise, requiring buffer areas and setbacks, and addressing the generating facility’s
decommissioning (Va. Stat. § 45.2-1708).
A locality is authorized to enforce the following at its discretion:
A siting agreement created by the locality may include guidance or requirements including but
not limited to mitigation of the solar facility’s impacts on the site, financial compensation to the
host locality based on specific capital needs, and the solar developer’s assistance in deploying
broadband (Va. Stat. §15.2.-2316.7).
Hire and pay consultants in matters pertaining to the solar facility’s siting (Va. Stat. §15.2.-2316.8).
Meet, discuss, negotiate, and enter a siting agreement with the applicant (Va. Stat. §15.2.-2316.8).
Allow the net salvage value of the solar project’s equipment, facilities, or devices to be subtracted
from the gross decommissioning cost (Va. Stat. §15.2.-2241.2).
Allow the decommissioning cost estimate to factor (i.e., add) a reasonable allowance for
estimated administrative costs related to a default of the owner, lessee, or developer, and an
annual inflation factor (Va. Stat. §15.2.-2241.2).
Create a local ordinance regulating the disposal of removed solar panels, in accordance with
Decommissioning Utility-Scale Solar Facilities 13
other applicable laws and regulations affecting their disposal (Va. Stat. §15.2.-2288.7).
Create a local ordinance addressing the siting of renewable energy facilities that generate
electricity from wind or solar resources (Va. Stat. § 45.2-1708).
Decommissioning Utility-Scale Solar Facilities 14
DECOMMISSIONING ORDINANCE
WHERE TO STATE DECOMMISSIONING REQUIREMENTS
A locality may formally state its decommissioning requirements via a:
universally applicable zoning ordinance
conditional use permit (CUP)
special use permit (SUP)
special exception (SEP)
negotiated siting agreement
It may also wish to apply some combination of the above. Some localities, for example, state their
guiding minimum decommissioning requirements in a zoning ordinance, and note any further
conditions in subsequent site-specific permits.
As of July 2022, just over twenty-five percent of Virginia’s 133 counties and cities have codified
utility-scale solar decommissioning requirements in a zoning ordinance. The use of locally-codified
decommissioning ordinances is nearly twice as high among the Commonwealth’s thirty-seven
localities with at least one operating utility-scale solar facility. Creating a zoning ordinance for
decommissioning offers the locality a guiding document when considering whether to accept a
proposed solar project. Codifying minimum decommissioning requirements in a zoning ordinance
also helps developers more accurately evaluate costs early in the siting process. A zoning ordinance
may be of further benefit to localities in cases where the host locality wishes to implement land-
management practices concurrent with the project or land restoration measures after the project
terminates.
A locality’s comprehensive plan indicates preferences and priorities for land-use, as well as the
county’s or city’s values and strategic goals. Localities generally verify that any discretionary
decommissioning requirements are in accordance with their comprehensive plan, which may contain
related goals such as renewable energy development, economic growth, or technological progress.
REFURBISHMENT AND REPOWERING
The construction of a solar installation generally requires costly, up-front site improvements whose
value may extend beyond the life of the solar panels initially installed at the site. These
improvements include site preparation and the infrastructure for connecting the facility to the grid.
Because these infrastructure assets will continue to have value even as the original panels age, solar
developers will often find it advantageous to repower an existing site by installing new panels and
using the already developed land and power improvements. Given the likely advantages of a future
repowering, developers and localities may find it advantageous to address the refurbishing or
Decommissioning Utility-Scale Solar Facilities 15
repowering of EoL facilities in either the locality’s zoning ordinances or permit process language.
Thus, in addition to requiring that operators maintain a decommissioning plan, localities could state
any preliminary conditions for re-permitting the land use of the facility at the end of the initial
expected life of the facility. Re-permitting can be valuable to both developers and localities, since the
repowered facility can have substantially lower costs. Note that a locality’s renegotiation of its
permission for a facility owner to continue using a parcel of real property for electricity generation is
entirely different from any financial agreements between the power producer and off-taker as
negotiated in a PPA, which does not involve the locality.
A locality may use a permit or siting agreement to enumerate the minimum conditions a facility’s
owner or affiliate should fulfill if they seek to repower the site at the project’s end (Wyatt, 2020).
Relevant permit language may be as simple as an extension clause. Examples from locally approved
utility-scale solar sites in Virginia include:
“The expected life of the Project is thirty (30) years with extension possible upon mutual
agreement with the landowners (“Project Life”).” (Conditional Use Permit Approval for Eastern
Shore Solar, 80 MW; Accomack County)
“The expected useful life of the Solar Farm Project is twenty-five (25) to thirty (30) years with an
extension possible upon mutual agreement with the landowners (the "Project Life").” (Conditional
Use Permit Approval for SunTec Solar Farm, 20 MW; Accomack County)
“The Owner reserves the right to extend the Project instead of decommissioning at the end [sic]
commercial operations with landowner permission and upon obtaining all necessary permits. If
the Owner seeks to extend the life of the Project, they will decide whether to continue operation
with existing equipment or to retrofit solar panels and power system with upgrades based on
new technologies." (Special Use Permit Application for Caden Energix Gladys, LLC, 60 MW;
Campbell County)
“If the Solar Facility is operated for greater than 35 years after the Agreement Date and after the
Termination Date, the Developer will use reasonable efforts to negotiate an extension of this
Agreement with the County.” (Siting Agreement for Randolph Solar Project, 800 MW; Charlotte
County)
“The expected life of the Project is thirty (30) years with possible extension (“Project Life”).”
(Conditional Use Permit Approval for Southampton Solar, 100 MW; Southampton County)
“The facility has an estimated useful life of at least 35 years with an opportunity for extension
depending on equipment replacements or refurbishments.” (Special Exception Permit Approval
for Montross Solar, 20 MW; Westmoreland County)
Decommissioning Utility-Scale Solar Facilities 16
RECOMMENDED DECOMMISSIONING ORDINANCE CONTENT
A decommissioning ordinance typically states the decommissioning procedure a locality requires the
site owner or operator to follow and specifies the appropriate contents of the decommissioning plan
a developer must file with the locality before constructing the facility or receiving site approval. It
also defines relevant legal terms and conditions and describes the minimum acceptable standards
for land restoration. While Virginia law requires developers 4 to enter into a decommissioning
agreement with their host locality, it does not mandate that localities develop a zoning ordinance
stating decommissioning requirements. If a locality does not wish to codify specific decommissioning
standards or the rights of the local governing body over the decommissioning process in its local
laws, it may still find it beneficial to state them in its decommissioning agreement with the project
owner.
Procedure
A decommissioning ordinance should state the conditions under which the facility’s owner must
initiate decommissioning; namely, site abandonment or the end of the project’s life, and the time
constraints by which decommissioning must be fully executed.
Prior to the cessation of operations, a locality may require the project owner to submit a written
notification that a site has reached the end of its project life, shall be non-operational, or is
scheduled to be abandoned to the relevant government official, such as the zoning administrator,
county administrator, county building official, or zoning and inspections director.
At its discretion, the locality may further establish a procedure for setting the official timetable for
decommissioning. Some Virginia localities, for example, have codified their right to issue a site-
specific “County Notice” or “City Notice” (hereafter, “Notice”) that the locality deems the facility
deactivated or abandoned and requires decommissioning to be fully executed within a set period of
time from the owner’s receipt of the Notice. Others specify that upon their receipt of the project
owner’s notice of non-operationality, or upon a zoning administrator’s subsequent site inspection
and confirmation that it would be timely and appropriate to initiate decommissioning, the site must
be fully decommissioned within twelve to twenty-four months.
Localities may reserve the right to issue a Notice if a site fulfills the criteria which would qualify it as
abandoned or deactivated even if the facility’s owner or operator has not submitted a written
notification of the site’s non-operationality. It is considered good practice to allow a window for the
owner or operator to appeal for approval to repair a non-operational site that has not reached the
end of its project life upon receiving a Notice. Should the need arise, a locality may also choose to
allow its relevant local governing body, such as its Board of Supervisors, to grant a decommissioning
extension or extensions.
Decommissioning Utility-Scale Solar Facilities 17
Terms and Conditions
Decommissioning: Localities generally define “decommissioning” as the removal and proper
disposal of all above-ground hardware, structures, and solar infrastructure along with removal of part
or all below-ground equipment upon a project’s abandonment, termination, or after its anticipated
useful life, in accordance with the decommissioning plan submitted to and approved by the locality.
Such a definition is consistent with that provided in §15.2-2241.2 of the Code of Virginia. Based on
NREL guidance and definitions implemented by localities in Virginia and other states, an appropriate
decommissioning specification may also include the reclamation of access roads and the restoration
of the land and related disturbed areas to agreed-upon conditions for subsequent use via soil
decompaction, soil stabilization, re-seeding, or revegetation. Based on site characteristics, it may be
necessary to delay the removal of any stormwater structures which should remain in-place during
the hardware removal and land restoration phases. In some cases, a locality may deem that certain
installations, such as stormwater structures or access roads, constitute real improvements to the site
based on its future land-use, and allow such installations to be exempted from decommissioning.
Abandonment, Deactivation, and End of Life: Virginia localities with abandonment or deactivation
clauses in their decommissioning ordinances typically identify a solar facility as abandoned if it
ceases to generate electricity for a continuous period of twelve months, with some localities’
definitions ranging between six and twenty-four months. To protect against abandonment in the
construction phase, localities may also include language quantifying the number of months a
developer has to reach an operational status before the conditional use permit must be
renegotiated. For example, a locality may specify that a solar facility shall held as abandoned if
construction on an initiated project remains incomplete twenty-four months after the locality has
approved the final site plan, with exceptions granted for interconnection delays due to the rolling
backlog of requests in the PJM queue. To avoid legal ambiguity, it is crucial that a decommissioning
ordinance clearly distinguish between the conditions of inactivity which constitute abandonment and
those that do not. These conditions are covered in greater detail in the “Legal Framework” section of
this paper.
Financial Considerations: A decommissioning ordinance will generally state which forms of posted
financial assurance the locality considers acceptable and should specify that financial assurance must
cover the full cost of decommissioning. It may allow, explicitly disallow, or remain silent on whether a
developer may factor part or all of hardware’s anticipated salvage value into the estimated net cost
of decommissioning. To guard against abandonment or financial insolvency early in the project, a
locality may require a developer to provide proof of liability insurance for the solar facility before
initiating construction.
Decommissioning Utility-Scale Solar Facilities 18
Rights of the Locality Regarding the Project Site: The locality should specify its right to enter and
remove the facility if decommissioning protocols have been activated but the owner or operator has
failed to fulfill them within a timely manner. Legal actions and remedies available to the locality in
such a case are further described in the “Procedural Framework” section of this paper. A locality may
require that it be granted the right to periodically enter and inspect the solar facility during
decommissioning. It may also wish to specify a framework by which the site owner or operator
should coordinate with local emergency services to train for responses to onsite emergencies,
provide site access, and develop an Emergency Operations Plan throughout the facility’s operational
period.
Land Management and Restoration
Land management requirements for a utility-scale solar site are more often specified in a siting
agreement or local land use permit rather than in a decommissioning ordinance. Even so, it is
appropriate for a decommissioning ordinance to state that a facility owner or operator must comply
with state and federal regulations for sediment and erosion control during site construction,
operation, and decommissioning. Because Virginia state law allows localities to enact sediment
erosion and control standards that are more stringent than those mandated by the state (Va. Stat.
§62.1-44.15:51), it may be prudent to reference any such regulations in the decommissioning
ordinance. Measures for protecting wetlands during decommissioning and maintaining watershed
nutrient load standards when amending soil should be similarly noted, where applicable and
necessary. Land restoration may include such measures as soil regrading, the application of soil
amendments, reseeding, revegetation, and the removal of all access roads and internal paths, or
those deemed relevant. It may also be necessary to re-grade, backfill, and re-stabilize areas
significantly impacted by the removal of any site components. The de-compaction of both topsoil
and subsoil horizons may be necessary as agreed to by the landowner, consistent with the future use
of the land or as required by then-current state laws and regulations.
The heavy machinery used to install and dismantle utility-scale solar PV systems can compact topsoil
and subsoil across the disturbed land area. While amending these soils with organic fertilizers and
replanting with native vegetation to the extent feasible 5 during and after the solar project’s life are
excellent land management and restoration practices (Horowitz, Ramasamy, Macknick, & Margolis,
2020; Walston et al., 2018), replanting alone will not reduce the bulk density of compacted soils
beyond a few inches over twenty to thirty years. Deep-rooted plants such as alfalfa and switchgrass
and chemical amendments such as gypsum may increase land productivity over time, but they
cannot in themselves loosen highly compacted topsoils and subsoils. If agriculture is the desired
5Author’s Note: Depending on site characteristics, it may be quite challenging to maintain native vegetation directly around active panel displays because of (1) the mowing standards by which a project owner must abide to fulfill safety and access requirements and (2) short- and medium-term erosion and sediment control measures (L. Daniels, personal communication, August 1, 2022). Native vegetation is encouraged where practicable.
Decommissioning Utility-Scale Solar Facilities 19
post-project land use, the locality should require the party responsible for decommissioning to
mechanically loosen and till the soil prior to revegetation.
Where decompaction is necessary, it is crucial that tillage is applied under the appropriate soil-
moisture regime, as ascertained by the site engineer. Overly dry soil will prevent the shank used for
tillage from cutting through the ground, and may cause a chisel plow, rototiller, or shank ripper to
eject large chunks of intact soil. Conversely, a shank will pass too smoothly through overly wet
ground and fail to shatter compact soil. The extent of tillage necessary will vary site-to-site and can
be easily determined by measuring the bulk density and texture of the upper inches of soil and
generating an estimate of the root-limiting bulk density, which is well-established in agronomic
literature. If possible, topsoil should be salvaged and re-applied in a loose, rough, and undulating
manner after tillage or cut-and-fill measures have been applied. These decompaction and soil
reconstruction practices sufficiently restore property for silviculture or hay-land pasture use, but for
USDA NRCS-designated prime farmland, NRCS prime farmland and state-designated “important
agricultural soils”, additional measures may be required to restore the land to its prior productivity (L.
Daniels, personal communication, July 5, 2022).
Decommissioning Plan
The decommissioning plan is typically submitted for review concurrent with a solar facility’s site plan.
A locality’s Planning Commission should review the decommissioning plan no less frequently than
once every five years after its initial approval. Based on guidance from existing decommissioning
plans, the North Carolina Department of Environmental Quality (2022, p. 12), and the Virginia-based
developer SolUnesco (Maamari, 2018), a decommissioning plan should contain:
Contact information for the landowner, site operator, and entity responsible for
decommissioning. This information should include the relevant parties’ names, titles, physical
mailing addresses, email addresses, and business names.
The anticipated project life, along with the current land-use (e.g., industry, agriculture,
silviculture) and the proposed land use (i.e., utility-scale solar development).
A cost estimate for decommissioning including the anticipated present value, an explanation
of the cost calculation applied, and a description of the financial assurance to be posted for
decommissioning that has been deemed acceptable by the locality’s relevant legal authority,
such as the County Attorney, including which legal entity shall establish the surety, when it
shall be established, and how the locality shall access it should the need arise.
Decommissioning Utility-Scale Solar Facilities 20
A decommissioning narrative describing the procedure through which decommissioning will
occur, a schedule for this procedure which includes the total estimated length and the
estimated duration of each activity, the disposal methods which shall be applied (e.g.,
hazardous waste vs. non-hazardous waste disposal, landfilling, reuse, recycling) in accordance
with then-current state and federal regulations, and a description of the expected site
conditions once solar facilities have been removed.
A salvage plan describing the procedures by which equipment will be recycled or resold in
licensed secondary markets, where possible.
A restoration plan detailing the quality to which the land will be returned and the actions
necessary to accomplish this.
Current decommissioning plans in Virginia generally describe the full removal of above ground
support structures, as well as below ground piles where practical. Removable hardware includes but
is not limited to solar panels, panel trackers, anchors, supports and mounts, inverter buildings,
electrical conductors, electrical cables, substation components, control cabinets, and fencing. Below-
ground components must usually be removed to thirty-six inches below finished grade or down to
bedrock, whichever is less. For a below-ground component such as a steel piling extending deeper
than thirty-six inches, the owner would be obligated to remove at least the upper portion of the
piling. In practice, because the piling is a single component, facility owners will remove the full
module. In the event that a sub-surface component breaks during removal, is embedded in bedrock,
or cannot otherwise be recovered, existing special use permits specify that the piece should be
excavated to a depth of at least thirty-six inches, with the remainder left in place and covered with an
appropriately-reconstructed soil profile (SolUnesco, 2018; L. Daniels, personal communication,
August 1, 2022). Some local governments allow a subsurface component to remain if the landowner
submits a written request for a waiver to the relevant local legislative body.
Solar waste should be recycled to the maximum extent feasible where such markets exist. While
current research indicates that solar recycling is generally unprofitable in comparison to landfilling
and without additional legislative protections (D’Adamo, Miliacca, & Rosa, 2017; Malandrino et al.,
2017; Lunardi et al., 2021), several European solar recycling paradigms have been shown to be cost
effective (Choi & Fthenakis, 2010; McDonald & Pearce, 2010) and impressive progress has been
made in designing full-module recycling systems (Klugmann-Radziemsa, 2012; Cucchiella, D’Adamo,
& Rosa, 2015; Latunussa, Ardente, Blengini, & Mancini, 2016; Heath et al., 2018; Faircloth et al., 2019;
Markert, Celik, & Apul, 2020; Peacock, 2021; Flores et al., 2022). Because comparable solar waste
markets, collection systems, and recycling facilities have not yet been realized in the mid-Atlantic
United States (Ovaitt, Mirletz, Seetharam, & Barnes, 2021), decommissioning ordinance clauses which
recommend solar recycling are beneficial but not enforceable. Recent guidance from the North
Decommissioning Utility-Scale Solar Facilities 21
North Carolina DEQ to its state’s localities hosting utility-scale solar projects encourages the
economic development of recycling and reuse streams for end-of-life solar panels (Scott, 2022).
Based on the federal government’s Resource Conservation and Recovery Act of 1976 (RCRA), solar
panels and system components which qualify as recyclable material may also be subject to
regulations for solid waste or potentially hazardous waste, depending on the content of the PV
module (40 C.F.R. §§ 261.2(a)-(c); 42 U.S.C. § 6903(27); 40 C.F.R. § 261.2(e)(ii)). For example, one
square meter of a thin-film cadmium telluride (CdTe) photovoltaic module contains about seven
grams of cadmium—about as much as a 4.6 cubic inch nickel cadmium (NiCd) flashlight battery
(note also that NiCd, being subject to the EPA’s Universal Waste Rule, is best disposed of via
recycling) (Zweibel, Moskowitz, & Fthenakis, 1998, pp. 1-2; Industrial Economics, 2004, p. 23).
Research conducted by the National Renewable Energy Laboratory suggests that the primary
federally approved method for testing solar panel toxicity, the Toxicity Characteristic Leaching
Procedure (40 C.F.R. §§ 261.11, 261.24) has variable results depending on the sampling location,
removal method applied, and laboratory used to analyze results (Curtis et al., 2021, p. 8; TamizhMani
et al., 2018). The EPA recommends the appropriate recycling or reuse of hazardous materials to
reduce soil pollution and the consumption of primary resources (EPA, 2021); thus, the activation of
an RCRA or TCLP hazardous waste designation should be understood as ensuring responsible waste
management rather than threatening environmental quality. If desired, a locality may adopt
regulations into their zoning ordinances that installed panels meet internationally recognized
standards of material quality. Such PV modules will still likely fall under RCRA’s purview. Any
hazardous materials should be removed and disposed of in accordance with then-current local, state,
and federal regulations. When solar hardware is recycled, resold in a licensed secondary market, or
otherwise appropriately disposed of, it is good practice for a developer to retain the manifests
provided by such sites which document the quantities and descriptions of the delivered materials.
Localities seeking additional guidance on PV material management may consider reviewing the
standards required in Washington, California, New Jersey, and North Carolina (NYSERDA, 2022).
Decommissioning Utility-Scale Solar Facilities 22
LEGAL FRAMEWORK FOR LOCALITY IN CASE OF
ABANDONMENT
Non-financial mechanisms can assure PV system decommissioning by defining a legal framework
which indemnifies the locality in the event of abandonment. These mechanisms often resemble the
regulations applied to ensure the decommissioning of telecommunications installations. The New
York State Energy Research and Development Authority (NYSERDA) identifies these key mechanisms
as an abandonment and removal clause, a special permit application, and a temporary variance
process.
ABANDONMENT AND REMOVAL CLAUSE
Localities should clearly define non-performance and abandonment and delineate the timeframes by
which (i) a project’s status is considered “abandoned”, (ii) an owner or operator may appeal an
abandonment status and/or correct the solar site, and (iii) the locality may access financial assurance
in the event that an abandoned project has not been decommissioned in a timely manner. An
abandonment and removal clause may outlay the terms for civil penalties and fines levied on the
owner or operator of an abandoned site. The locality may further state its ability to impose a lien on
such a property to recover decommissioning costs in cases where financial assurance is inaccessible
or otherwise insufficient to remove the solar facility. Both “abandonment” and “removal” should be
clearly defined to eschew any legal ambiguity. The timeframe allotted for decommissioning an
abandoned or end-of-life project should be sensitive to the solar facility’s size, location, and
complexity.
Localities should also specify the contexts in which it is permissible for a solar site to remain
continuously inactive for an extended period without being designated abandoned. An analysis of
decommissioning ordinances enacted by Virginia localities indicates that acceptable non-
abandonment scenarios may include but are not necessarily limited to:
A force majeure event that has occurred or is occurring, which will prevent the facility from
resuming operations within twelve months;
A project in the process of being repowered;
A project pending completion of construction due to a backlog of cases or service requests in
the PJM interconnection queue;
A situation in which the owner or operator can provide evidence to the relevant local governing board, such as the Board of Zoning Appeals or Board of Supervisors, that the site’s period of continuous inactivity is due to circumstances beyond their control and the facility has not been
abandoned; and
Decommissioning Utility-Scale Solar Facilities 23
An appeal of the County Notice or City Notice within a set time from its receipt (e.g., 45 days) in which a facility owner explains the reasons for operational difficulty and provides a timetable for
corrective action which the locality deems reasonable.
SPECIAL PERMIT APPLICATION
In the absence of a solar ordinance that requires a decommissioning plan, a locality may, as a
condition of SEP/CUP approval, require the Final Site Plan review to include its approval of a
complete and accurate decommissioning plan (NYSERDA, 2022). The locality may also require a
conceptual decommissioning plan as a condition of special permit approval, understanding that
component-specific details and site design may not be finalized until the Final Site Plan review.
Codifying a decommissioning plan requirement protects the locality’s interests in that (i) the locality
is authorized to request any significant revisions to the decommissioning plan or procedure before
approving the Final Site Plan, and (ii) the local government may apply the approved, complete
decommissioning plan as a framework for assessing decommissioning noncompliance at the end of
a project’s life or in the case of abandonment.
TEMPORARY VARIANCE PROCESS
Issuing a land variance or special or conditional use permit for a utility-scale solar facility allows the
locality to exercise its regular zoning enforcement authority to remove an abandoned or otherwise
non-operational facility. It further allows the locality to re-license the facility, if desired, once the
project term expires (NYSERDA, 2022).
EXAMPLES
Abandonment clauses protecting the locality against bearing decommissioning costs state the point
at which the locality may access financial assurance, enter the site without the owner’s site to
complete decommissioning, or pursue other legal action for failing to decommission the site within
the agreed-upon period. Note that while the locality’s right to enter a solar facility without the
owner’s consent and engage in decommissioning is protected under Section 15.2.-2241.2 of the
Code of Virginia, it is considered good practice to restate this right in a decommissioning ordinance,
siting agreement, and/or condition for land use. Relevant examples from Virginia localities’ solar
decommissioning ordinances are shown below, with emphasis added:
(a) Legal action and liability statements:
“…the county may pursue legal action to have the facility removed at the expense of the facility owner, site owner, or operator, each of whom shall be jointly and severally liable for the expense of removing or repairing the facility.” (Appomattox County Code, §19.6-97.6; Halifax
Decommissioning Utility-Scale Solar Facilities 24
County Code, §53-160; Prince Edward County Code, §7-114)
“If the owner or operator fails to remove or repair the unsafe solar energy project, [the county] may pursue a legal action to have the project removed at the owner’s or operator’s expense.” (Dinwiddie County Code, §22-234.68; Henry County Code, §21-1807; Southampton
County Code, §18-367)
“If the facility is not removed within the specified time after the County Notice, the County may cause the removal of the facility with costs being borne by the project owner.” (Piedmont Environmental Council utility-scale solar development policy draft for Culpeper County,
unadopted)
“The surety shall be sufficient to indemnify the County if it incurs costs to rectify any violations of applicable codes, or to remove obsolete or abandoned renewable energy facilities in the event the applicant, its successors or assigns, fails to comply with any condition of the permit, which
the County may undertake to do if the applicant, its successors or assigns fail to do so within 90 days of notice from the Zoning Administrator of a violation of any provision of this chapter or any of the permit conditions imposed by the Board.” (Rappahannock County Code, §170-64)
“Within three hundred sixty-five (365) days of the date of abandonment or discontinuation, the owner of the system shall physically remove all components of the solar energy facility. If not removed within the allotted time, the county may have it removed at the expense of the
property owner.” (Rockingham County Code, §17-607)
“If the owner or operator fails to either notify the County Administrator or a designee that the large-scale solar facility is an abandoned large-scale solar facility or to decommission the
abandoned large-scale solar facility upon request of the County, the County may, in addition to any other remedies available under the law, cause the abandoned large-scale solar facility to be decommissioned and recover against the bond posted pursuant to § 165-174E the costs
of such decommissioning.” (Shenandoah County Code, §165-174H)
“If removal to the satisfaction of the county does not occur within one (1) year from the date of abandonment then the county may remove and salvage the component(s) and all supporting equipment using the decommissioning surety. Should the surety fail to adequately fund the
decommissioning of the site(s) the county will recover any difference, including attorney fees and any zoning violation fines, if applicable, through legal action against the designated responsible party or parties identified in the decommissioning plan, applicant, and/or landowner(s) party to the SUP, and their respective successors and assigns.” (Spotsylvania County
Code, §23.4.5.7)
(b) Entry right statements:
“If the owner, lessee, or developer defaults in the obligation to decommission the facility, the county has the right to enter the real property without further need of consent of the owner to engage in decommissioning.” (Alleghany County Code, §66-762; Gloucester County Code, §9-28)
Decommissioning Utility-Scale Solar Facilities 25
“If the party that enters into such written agreement with the County defaults in the obligation to decommission such equipment, facilities, or devices in the timeframe set out in such agreement,
the County has the right to enter the real property of the record title owner of such property without further consent of such owner and to engage in decommissioning.”
(Campbell County Code, §22-32; Isle of Wight County Code, §5-5003)
“If the terms of the decommissioning agreement are not met, the county may collect the surety and may enter the site to remove the equipment, apparatus, or any other personal property or improvements placed on the real property as a part of, or in connection with, the solar facility as it deems appropriate.” (Brunswick County Code, §23-407)
“If the facility owner/operator fails to remove the installation in accordance with the requirements of this permit or within the proposed date of decommissioning, the County may collect the bond or other surety and the County or hired third party may enter the property to physically remove the installation.” (Amelia County Code, §325-34.2)
“In the event the holder of a conditional use permit for a utility solar energy facility breaches the obligations put forth in the written agreement, the city may utilize the financial assurance, in whole or in part, to enter the property and engage in decommissioning the site without the owner's consent.” (City of Chesapeake Code, §13-2702)
“If the applicant, its successor, or the property owners fail to decommission the solar energy facility within six (6) months,6 the County shall have the right, but not the obligation, to
commence decommissioning activities and shall have access to the property, access to the full amount of the decommissioning surety, and the rights to the solar energy equipment and materials on the property.” (Prince George County, draft solar energy facility siting policy,
unadopted)
6 Author’s Note: Emerging best practice is to allow the facility owner a minimum of twelve months to fulfill all decommissioning
requirements.
Decommissioning Utility-Scale Solar Facilities 26
FINANCIAL ASSURANCE
Whether as part of a decommissioning plan, a zoning ordinance, or a condition of the solar facility’s
approval, a locality should require the project’s owner or affiliate to post financial assurance (FA)
equal to the full amount of the estimated decommissioning costs. These costs generally include
labor, infrastructure removal and transportation, recycling, disposal, and site restoration and
reclamation (Curtis et al., 2021). Localities frequently interchange the term “surety” with “financial
assurance”. While “surety” technically refers to the person who assumes direct liability for another
party’s debt or other legal obligation upon the closing of the land-use agreement (Cornell Law
School, 2022; Garner, n.d.), substituting the terms “surety” or “surety amount” for FA is an accepted
practice.
The amount, type, and posting time(s) of FA will depend on the size, complexity, and duration of
operation of the solar facility, as well as the site owner’s access to capital; as such, FA varies across
utility-scale solar projects. It is standard best practice to require that the surety amount be adjusted
at least every five years based on a Virginia-licensed engineer’s re-evaluation of decommissioning
costs. State law also allows the annual application of an inflation factor to the original
decommissioning cost estimate so that the total decommissioning security reflects real market costs.
Localities should be aware that removal costs may both fluctuate and can change at different rates
than the market rate of inflation. An engineer’s regular recalculation of the decommissioning cost
estimate may thus provide a more precise estimate of site removal costs than applying an inflation
factor would. If decommissioning costs are periodically reassessed, it is redundant to include an
inflation factor.
FA should also always be posted until the end of the decommissioning process, regardless of the
point at which the locality requires the project owner to begin posting it. As such, a solar
decommissioning regulation that contains language resembling the following is encouraged:
“The full amount of the specified financial assurance must remain in full force and effect until the Project is decommissioned and any necessary site restoration is completed,”
“At its option, the County / City may require the financial assurance amount change based on the
net cost of decommissioning,” and,
“In the event of abandonment or failure to decommission, the County / City shall have access to
the full amount of the specified financial assurance.”
Decommissioning Utility-Scale Solar Facilities 27
WHAT KINDS OF FINANCIAL ASSURANCE SHOULD A LOCALITY ALLOW?
It is in both the locality’s and the project owner’s best interest to provide the local government with
the necessary security for full decommissioning at the lowest cost to the developer. The most
appropriate FA mechanism may change in cases where a solar project comes under new ownership,
as the latest holder may have a different level of access to capital (MDOC, 2018, p. 7). While all FA
types are capital-intensive, some require considerable expenditures for annual maintenance and may
impose undue financial hardship on the facility owner or affiliate. Similarly, others may be inefficient
to apply where the developer is a well-established entity with very strong financial backing.
Commonly accepted financial assurance mechanisms and the situations in which they may be most
useful to a locality are described below. A locality should always require that any third-party financial
institutions or bank accounts involved in maintaining and procuring the FA are federally insured.
Trust Funds
Financial institutions employ a Trustee to manage trust funds on behalf of the project’s owner. Trust
funds may be used alongside additional FA mechanisms, such as a surety bond or letter of credit. A
trust fund is both capital-intensive—the developer often must pay all or much of the
decommissioning cost into the trust fund at the project’s outset, as well as the administrative costs
for the Trustee investing and managing the fund—and relatively risky, as the trust fund is susceptible
to market volatility. Any return on the invested funds that outpaces general inflation or industry-
specific increases in decommissioning costs would reduce capital costs for decommissioning faced
by the developer, who may then be able to receive funds in excess of the decommissioning cost. If
decommissioning costs rise unexpectedly or the trust fund performs poorly in the investment market
to the point that its worth is less than the decommissioning cost estimate, the developer will need to
deposit additional payments to true up the security (Richards, n.d.). Thus, the project owner or
developer may incur the additional burdens of remaining in contact with the Trustee managing the
trust; filing riders or amendments in the Trust Agreement between the solar site and the financial
institution and notifying the locality if the Trustee or financial institution changes name or undergoes
a merger; constantly monitoring the trust’s value; and verifying that administrative fees are not
eroding the trust fund’s value (EPA, n.d., “RCRA Fact Sheet: Trust Fund”). If the solar project changes
ownership, the trust fund will not automatically transfer to the successor company.
Cash Escrow
A solar project owner or developer may deposit funds into a cash escrow account maintained by a
federally insured financial institution. Once the project owner fulfills the decommissioning
requirements set by the locality at the end of the facility’s life, the bank will release the funds
deposited in the cash escrow account back to the developer. If the solar project is abandoned or
insufficiently decommissioned, the bank will grant the locality access to the cash escrow account to
complete the decommissioning process. A locality may require the developer to post full funding for
Decommissioning Utility-Scale Solar Facilities 28
decommissioning at the beginning of the project’s life or according to a fee schedule set in the use
permit approval.
While a cash escrow account is relatively simple to administer, it imposes high costs on the facility’s
owner. Developers with strong credit and capital access are less likely to implement cash escrow as
their preferred FA mechanism; in fact, it may be the only surety option available to smaller
developers with limited credit access (MDOC, 2018, pp. 8, 30). Similar to the restrictions of a money
market account, the funds held in cash escrow remain inaccessible to the solar facility’s owner or
affiliates for the duration of the project. Prior research suggests cash escrow accounts are sufficiently
costly to utility-scale solar developers that, if a locality requires cash escrow but disallows salvage
value, a developer is likely to withdraw the project altogether (Maamari, 2018). Thus, localities
stipulating cash escrow as a financial assurance mechanism should (i) establish a preset schedule of
deposits to the account, so the project owner does not bear decommissioning assurance as an
upfront cost, and (ii) include a salvage credit so account maintenance costs are not prohibitively high
early in the project life.
Letter of Credit
A letter of credit (LC) is a federally insured financial institution’s legally-binding written guarantee
that it will pay a beneficiary—here, the locality—under specified conditions, such as if the developer
defaults on decommissioning or abandons the solar project, until the LC’s expiration date, usually
one year from issuance (U.C.C. § 5-103(a), 1995), unless the developer renews the LC annually. For
the term that the LC exists, the issuing bank may impose an unsecured credit pool (UCP) lien or
Uniform Commercial Code (UCC) lien on the solar developer equaling the amount of the LC. The LC
thus appears as a footnote on the solar company’s balance sheet indicating its future
decommissioning liability and may impact the company’s ability to access credit markets (Freeman,
2020). Should the solar company fail to decommission the project in accordance with the terms of its
contract with the locality, the locality will receive sufficient decommissioning funds from the issuing
bank. The solar company must then reimburse the issuing bank for any payments to the locality.
A financial institution will typically require a solar company seeking a letter of credit to post
collateral—cash or non-cash—equaling between 0.5% and 1% of the LC’s face value, and to establish
a standby trust fund from which the bank would pay for decommissioning and land restoration
activities. The letter of credit and standby trust fund may be issued by different financial institutions.
The LC’s issuing and maintenance costs vary with the solar developer’s or owning firm’s
creditworthiness: annual renewal fees range from one percent to five percent of the letter of credit’s
face value (MDOC, 2018; Richards, n.d.), and can thus become quite costly. For example, if a bank’s
renewal fee is 3% per annum on an LC with a $435,000 payout, the project owner would need to pay
more than $13,000 annually simply to maintain the surety amount. Despite these conditions—
collateral, renewal fees, and the establishment of a standby trust fund—letters of credit may be
Decommissioning Utility-Scale Solar Facilities 29
relatively less expensive than posting cash escrow, even for less financially solvent developers.
Moreover, because a letter of credit is publicly filed, a locality can verify its value more easily than it
can a cash escrow account (Nusgart, 1998).
If a locality allows decommissioning security to take the form of a letter of credit, it should (i) specify
an irrevocable LC, (ii) include an evergreen clause, and, as in all cases, (iii) abide by the typical
precautions associated with storing and implementing a legally binding financial document. While an
irrevocable LC cannot be revoked or conditionally altered by the bank or the project owner, the
payout amount guaranteed by the LC should accurately reflect changes in the estimated cost of
decommissioning. If decommissioning costs significantly increase or decrease, adjustments in the
payout promised by the irrevocable LC can only occur with the explicit agreement of the project
owner, the beneficiary, and the issuing bank. Requiring an irrevocable LC thus ensures that no
changes can be made to the decommissioning security without the locality’s knowledge and consent.
Requiring that an LC have an evergreen clause causing the FA’s automatic annual renewal offers
further assurance to the locality in that its access to decommissioning surety from the LC’s original
signing is not compromised. Because the solar company would already need to maintain the LC
year-to-year, an evergreen clause poses no unanticipated financial burden on the developer. Finally,
since the LC is a cash instrument, the issuing bank’s liability is strictly enforceable (Downey, 1988, p.
6): The locality can access the standby trust fund only upon presenting the original, signed LC and
any other documents required by the financial institution. As such, the locality should maintain the
original LC in a secure location inaccessible to the public (EPA, n.d., “RCRA Fact Sheet: Letter of
Credit”).
Surety Bond Guaranteeing Payment or Performance
In a surety bond agreement, the Surety—a third-party insurer such as a bank insurance company—
agrees to complete decommissioning or uphold the project developer’s financial obligations for the
landowner’s or locality’s benefit if the developer defaults, abandons the project, or otherwise fails to
decommission the solar facility (Garner, n.d.; Curtis et al., 2021). To access the surety bond, a locality
typically must notify the Surety that the solar company, or Principal, failed to decommission the site.
After verifying the locality’s claim, the Surety will pay decommissioning funds into a standby trust
fund for the locality’s use. The Principal must reimburse the Surety for any outstanding
decommissioning costs.
Different types of decommissioning surety bond exist, the most common being a payment or financial
guarantee bond. Bond companies will less frequently extend a performance bond, which largely
resembles a payment bond in structure and execution except that the Surety may decide whether to
put an activated decommissioning bond in a standby trust fund or use the bond to hire contractors
and carry out the decommissioning requirements itself (Richards, n.d.). A solar project owner cannot
combine a performance bond with other financial assurance mechanisms, but a payment bond or
Decommissioning Utility-Scale Solar Facilities 30
financial guarantee bond can be used in conjunction with other FA options. All surety bond types are
generally paid into a standby trust fund if the locality informs the bond company that the project
owner has failed to decommission (EPA, n.d., “RCRA Fact Sheet: Surety Bond”).
To obtain and maintain a surety bond, the Principal must pay the bond company an annual premium
equaling a percentage of the decommissioning bond amount (MDOC, 2018; Maamari, 2018). This
annual premium usually ranges from 1 to 3% of the decommissioning bond’s face value; of course, if
a developer has poor credit or the bank assesses a solar project as relatively riskier, the bond
premium could rise as high as 15% (Freeman, 2020). Although circumstances vary across projects,
surety bonds do not have the same credit rating implications as letters of credit and may thus be
relatively less costly for a developer while still providing the same level of decommissioning security
to a locality.
Insurance
A solar company may take out a fully-funded or “finite” insurance policy equaling the net present
value of its expected decommissioning liability. It pays this liability amount either through a single
up-front insurance premium, or in phases of premiums paid during some portion or all of the solar
project’s life. As a result, the solar company pays for decommissioning twice: Once through the
insurance policy, and again upon actual decommissioning. The locality may then direct the insurer to
reimburse the solar company for incurred decommissioning costs once the removal and restoration
terms have been fulfilled (Richards, n.d.).
Another insurance mechanism, a risk transfer policy, moves the solar company’s decommissioning
liability to the insurer through the company’s payment of a premium to the insurer throughout the
project’s life (EPA, n.d., “RCRA Fact Sheet: Insurance”). Risk transfer policies more commonly occur in
oil and gas decommissioning projects, for which temporal uncertainties regarding a project’s life and
unknown total liabilities during and after closure could cause the project owner or operator to fail to
perform decommissioning due to financial distress (Barnes, 2018). Solar decommissioning is far more
straightforward: the process is less costly, the project life is pre-negotiated, the facility is relatively
smaller, hardware removal has few engineering and environmental complexities, and land restoration
requirements can be fulfilled within weeks to months. A risk transfer policy is not inappropriate in a
solar decommissioning context, but insurers may prefer underwriting fully-funded insurance policies,
which more effectively limit the insurer’s risk exposure (EPA, n.d., “RCRA Fact Sheet: Insurance”).
Despite their expense, insurance policies offer some flexibility: They do not require the establishment
of a standby trust fund and can be paired with additional financial assurance mechanisms. If
decommissioning costs change, the solar company can alter the policy’s face value relatively easily.
For increases in the decommissioning cost estimate, the company could also pair the insurance
policy with another locality-approved FA mechanism.
Decommissioning Utility-Scale Solar Facilities 31
A locality allowing decommissioning insurance should structure necessary requirements of the policy
among the decommissioning conditions of the use permit, and should exercise due diligence by
monitoring an active policy. Similar to other FA mechanisms, the insurance policy would fail to hold
in the event of decommissioning default if the insurer canceled the policy or became bankrupt. By
design, an insurer can only cancel a policy if the company fails to pay its premium. Thus, the locality
should monitor both the insurer’s financial solvency and that the solar company pays all its
premiums. Any insurance policies for decommissioning should be subject to the locality’s approval.
Based on an overview of existing utility-scale solar ordinances in Virginia and an analysis of the EPA’s
recommendations for closure and post-closure insurance, a locality accepting decommissioning
insurance should require the following conditions to hold:
The insurance policy should contain a provision transferring the policy to the successive owner or operator of the solar facility if it is sold by the original policyholder;
The insurer cannot cancel, terminate, or fail to renew the policy except for failure to pay the premium;
The policyholder must send a notice of cancellation to the relevant local/state authorities upon failure to pay the premium; and
If the insurer cancels the policy, the owner or operator must obtain an alternate form of financial assurance, subject to approval by the locality.
The locality may specify these requirements in the use permit for the solar facility, in its
decommissioning ordinance, if it exists, as a condition of the decommissioning insurance approval
process, or where otherwise relevant and prudent.
Guarantee by an Investment-Grade Entity
An investment-grade entity holds long-term unsecured debt obligations rated at least BBB- or above
from S&P Global Ratings and Baa3 or above from Moody’s Investors Service, or holds a comparable
credit rating from a currently registered Nationally Recognized Statistical Ratings Organization
(NRSRO) such as Fitch or Egan-Jones (SEC, 2017; SEC, 2022). A solar company which qualifies as an
investment-grade entity could extend a parent guarantee or promissory letter as proof for the
locality that it will fulfill its decommissioning responsibilities. Alternatively, if a solar developer has a
sufficiently large, stable, and tangible net worth to pass a corporate financial test, a locality may
waive the requirement to post decommissioning security, accepting the financial test as a
demonstration of the company’s ability to self-insure decommissioning costs.
Decommissioning Utility-Scale Solar Facilities 32
Corporate Financial Test
A company meeting the requirements of a corporate financial test indicates its ability to self-insure
for the cost of decommissioning based on the magnitude and soundness of its net worth and
working capital. Passing a corporate financial test is not equivalent to a legally binding guarantee
that an investment-grade company will uphold its decommissioning requirements, but because a
company can only pass the test if its net worth is six times the sum of the estimated
decommissioning and land restoration costs it will face, it is unlikely that a company which passes
the test would go bankrupt in the next year. As long as a company continues to demonstrate
financial solvency by passing the corporate financial test, the locality may waive the developer’s
requirement to post decommissioning security through a third party without exposing itself to any
significant risk of bearing decommissioning costs for an abandoned project.
The following corporate financial test procedure is based on the EPA’s guiding practices on
decommissioning security for end-of-life RCRA Subtitle C facilities. Subtitle C sites, such as
deactivated nuclear power plants or municipal solid waste landfills, involve the containment of
hazardous waste. While end-of-life PV panels may be subject to RCRA disposal guidelines, solar
farms themselves are neither toxic nor pollutive of air, water, or soil resources, and follow
decommissioning processes quite different from RCRA Subtitle C facilities. The EPA’s guiding
practices for corporate financial tests in non-analogous decommissioning situations provide a useful
framework of the financial proofs which solar developer should provide if they seek valid alternatives
to posting working capital as decommissioning security during the project’s life.
There are two separate tests, or “alternatives” within a corporate financial test. Each alternative has
four criteria. To pass a corporate financial test, a company must fulfill all four criteria within a single
alternative. Criteria one and two are the same across both alternatives:
Alternative I
Criterion 1: The company must have a tangible net worth greater than $10 million.
Criterion 2: The company’s U.S. assets equal at least 90% of its total assets or six times the sum of
its decommissioning and land restoration obligations.
Criterion 3: The company’s net working
capital and tangible net worth must each be
at least six times the sum of its
decommissioning and land restoration
obligations.
Criterion 3: The company’s tangible net worth
must be at least six times the sum of its
decommissioning and land restoration
obligations.
Decommissioning Utility-Scale Solar Facilities 33
Criterion 4: The company must pass at least
two of the three following ratios:
Its ratio of total liabilities to net worth
must be less than 2:1.
Its ratio of the sum of net income,
depreciation, depletion, and amortization
to total liabilities must be greater than
1:10.
Its ratio of current assets to current
liabilities must be greater than 1.5:1.
Criterion 4: The company’s most recent bond
issuance must have a rating of at least BBB
from Standard & Poor’s and at least Baa from
Moody’s.
If the company responsible for decommissioning the solar facility passes the corporate financial test,
the locality should monitor the company’s financial status throughout the project life to verify the
company’s ability to self-insure the estimated decommissioning costs. The locality can build these
monitoring practices into the conditions for using a corporate financial test by applying the
following:
The locality could require the company to provide its financial statements for the most recent year to an independent Certified Public Accountant, who shall examine and produce an audit report on them.
The financial test must be re-taken at least every year and when decommissioning cost estimates change to verify that the guarantor maintains at least the minimum tangible net worth and bond rating.
Separate from use requirements, a locality accepting a corporate financial test should further:
Verify the company’s bond ratings and financial ratios annually. A locality may also be able to access the company’s Form 10-K filed with the SEC, if the company has at least $10 million in assets and at least 500 shareholders, or if its lists its securities on an exchange or NASDAQ. A Form 10-K offers a useful summary of the corporation’s business and financial condition upon the end of its fiscal year, including audited statements (SEC, 2021).
Remain aware of negative changes in (i) the size of the buffer by which the company passes the financial test, (ii) the company’s fiscal year-end, and (iii) business press regarding the company’s bond ratings, stock prices, or mergers and acquisitions, as any of these may indicate the company’s financial distress.
Decommissioning Utility-Scale Solar Facilities 34
Parent Guarantee
A parent guarantee is only available to solar developers affiliated with a parent company with a large
and stable net worth (MDOC, 2018, p. 9). Similar to a corporate financial test, the locality is
responsible for assessing the parent company’s financial ability to bear the costs of decommissioning
and may consider the parent company’s asset to liability ratio, net worth, and credit exposure.
Utilities regulated by the SCC, such as Dominion Energy, are typically able to offer parent guarantees
for decommissioning security. Depending on additional state and federal regulations which their
subsidiary division is subject to, a publicly regulated utility may prefer to offer a comparable form of
financial assurance, such as a promissory note.
Promissory Note
An owner or operator of a solar facility who gives a promissory letter or promissory note for
decommissioning makes a legally binding, unconditional promise to pay the costs associated with
decommissioning an end-of-life or abandoned solar facility to the holder of the note, namely the
locality, if the facility is not decommissioned in the required manner. Promissory notes typically
provide a maturity date and specify the amount of the promised payment, along with the terms for
payment.
Additional Considerations
Localities Rarely Accept Salvage Value Alone as FA
While the estimated decommissioning cost should factor salvage value, localities generally do not
accept salvage value alone as sufficient financial assurance for decommissioning, even in cases where
an engineer’s decommissioning cost estimate suggests that salvage value exceeds removal costs. In
the current market, salvage values exceeding the total decommissioning cost estimate may overstate
resale and recycling values. This may change as secondary markets develop and is an important area
for monitoring and future research.
Pooled Funds
It is impractical and highly costly both to the developer and the locality to implement a pooled fund
to assure decommissioning. Pooled funds are used—often under federal mandate—to
decommission highly-regulated sites such as nuclear plants, oil wells, and hazardous waste facilities
(MDOC, 2018; 26 CFR §1.468A-5). Owners of the same category of facility deposit payments or
investment options into a decommissioning fund which each contributing owner may access under
specific circumstances to execute decommissioning. The high levels of funding and administrative
expertise necessary to operate a pooled fund, matched with the relative simplicity of
decommissioning utility-scale solar facilities, make pooled funds an economically infeasible FA
mechanism for solar sites.
Decommissioning Utility-Scale Solar Facilities 35
Pooled Insurance
A similar approach, pooled insurance for decommissioning, is infeasible at present for different
reasons. Under a pooled insurance model, multiple solar developers could fund decommissioning
security by contributing individual premiums to a group fund. A neutral manager of the pool,
typically an insurance underwriter, would evaluate each project's decommissioning plan, each
developer's financial status, and a table of historical losses—that is, decommissioning liability
claims—from comparable sites to determine individual participants' risk that they would fail to
complete decommissioning. This probability of failure, multiplied by the facility owner's total
decommissioning obligation and factoring any administrative costs for managing the insurance pool,
would yield the developer’s contribution to the fund. In the event that one of the participating
developers should default on their obligation, the full FA amount would be paid out from the fund to
the affected locality.
There are several likely challenges associated with the take-up and rollout of a decommissioning
insurance pool. As of August 2022, no insurers in the Commonwealth of Virginia underwrite pooled
decommissioning insurance policies for utility-scale solar facilities. Nationally, the limited cases
where pooled insurance for utility-scale solar projects have occurred are in relation to liability claims,
such as from hailstorm damage or wind-loosened panels, and not EoL decommissioning (Schwab,
Walker, & Desai, 2020). Moreover, because there is a very limited history of defaults on solar
decommissioning obligations, it would be difficult for an underwriter to establish a schedule of
actuarially fair prices for developers. If an underwriter overestimates a facility owner’s default risk, the
insurance premium paid by the owner could be relatively higher than under an individual insurance
policy or alternative FA mechanism, and therefore present a suboptimal FA situation for the solar
developer. Conversely, if the insurer undercalculates the facility owner’s default risk, it will be
responsible for paying extensive FA claims to the locality in the event of failure to decommission.
While it is unlikely that the pool of funds would be insufficient to pay out decommissioning claims to
localities, it remains possible that localities could face additional complications or lags in their access
to a pool of funds if multiple project owners default on their decommissioning obligations.
Applying a pooled insurance paradigm further requires solar projects across counties to participate
in the same pool. This restricts the pooled insurance mechanism to future projects, demands greater
coordination across localities, and could introduce delays to projects where coordination is uncertain
or pre-coverage negotiations are necessary. While a decommissioning insurance pool is possible, the
lack of a relevant model for utility-scale solar facilities may make it a daunting FA alternative for both
localities and solar developers at this time.
Decommissioning Utility-Scale Solar Facilities 36
Summary of Financial Assurance Mechanisms
FA
Mechanism Description Benefits Disadvantages Additional
Considerations
Trust Fund
The solar developer (“Grantor”) transfers assets sufficient to cover the estimated decommissioning costs to a trust held and
administered by a
financial institution
(“Trustee”).
surety bond or letter of
credit.
Phased deposits may be
allowed. If the trust fund
accrues investment
income, the locality may thus reduce future deposits required from
funds: highly expensive
to establish and
maintain; subject to
market volatility.
If facility ownership
changes, the trust fund does not automatically transfer to the
Trustee manages assets
for the benefit of the
locality (“Beneficiary”).
If the trust’s value
exceeds the
decommissioning cost estimate, funds may be released to the solar company.
Cash Escrow
The solar developer
deposits funds sufficient to cover the estimated decommissioning costs to an account at a federally insured financial institution.
be allowed.
Funds in the cash escrow account will be released to the
developer if
decommissioning is
Highly expensive to establish.
May be the only FA mechanism available to
solar developers with
less credit access.
Scheduled deposits rather than upfront
payment and factoring
salvage value can
reduce expense.
Escrow agent is an
impartial asset holder.
Letter of Credit (LC)
The issuing bank
substitutes its credit for
the developer’s. Establishment requires the developer to post collateral usu. worth 0.5% to 1% of the LC’s face value. If facility ownership
changes, the prior owner
is not released from the
LC until the successor company provides alternate FA.
locality to verify LC’s value and access LC than is the case with a cash escrow account.
In some cases, it may be easier for a locality to access LC funds than
surety bond funds.
An irrevocable LC
cannot be revoked or
altered by the issuing
Costly annual renewal fees.
May negatively affect the solar company’s credit and borrowing access.
LC does not automatically transfer to successor company if
facility ownership
changes.
include an evergreen clause so the LC automatically renews each year.
Requires a standby trust agreement.
(Irrevocable LC:) The Surety can alter the payout amount only
with the consent of the
bank, the locality, and
Surety Bond
The Surety, a bond company or bank
insurance company,
provides its financial
backing to the locality on behalf of the developer, and takes on decommissioning obligations up to the bond limits if the
developer (“Principal”)
abandons or fails to
decommission the facility.
through the Principal’s payment of an annual premium equaling 1 to 3%
of the bond’s face value.
Publicly filed, and therefore
relatively easier for a
locality to verify surety
bond’s value than is the
case with a cash escrow account.
May be less expensive for developer than cash
Can be an expensive option, depending on cost of annual premium.
Locality must file a written claim with Surety to obtain decommissioning funds.
Surety verifies locality’s
claim that
decommissioning terms have been violated before granting the locality access to the FA.
performance bonds differ. A payment bond requires a standby trust agreement. For a performance bond, the
bonding company may
pay out funds to a
standby trust fund or hire a contractor to execute decommissioning.
Cost paid by Principal depends on creditworthiness and
Decommissioning Utility-Scale Solar Facilities 37
FA Mechanism Description Benefits Disadvantages Additional Considerations
Insurance
(Finite policy:) The solar company pays the insurer the net present value of the expected decommissioning liability. The locality may direct
the insurer to reimburse
the solar company for
incurred decommissioning costs.
Can be used with other
FA mechanisms.
Insurance premium may be paid as a single up-front cost or in phases.
Responsive to
adjustments in decommissioning cost estimate.
Can be prohibitively expensive, as the company pays for
decommissioning twice
before reimbursement.
The locality should monitor both the insurer’s financial solvency and that the solar company pays all
its premiums.
is required.
May take the form of a fully-funded (finite) policy or, less commonly, a risk transfer policy.
The insurer can only cancel the policy if the company fails to pay its
Corporate Financial
Test
Developer self-insures cost of decommissioning (i.e., does not post
security) by proving large
Developer is extremely unlikely to become
financially insolvent.
Generally excludes
developers unaffiliated with parent companies, or whose parent companies do not have a large and stable net worth.
Locality should verify
and monitor company’s
financial ability to bear decommissioning obligations throughout the project life, potentially increasing the locality’s
administrative costs.
Promissory Letter or Parent
Guarantee
Developer’s parent company proves financial solvency and promises to pay any
decommissioning
obligations.
unlikely to become financially insolvent. Developer does not usually post decommissioning security. Usually limited
in application to
publicly regulated
utilities.
Decommissioning Utility-Scale Solar Facilities 38
WHEN SHOULD A LOCALITY REQUIRE AN OWNER OR AFFILIATE TO POST FA?
The cost-minimizing, security-maximizing timeline by which an owner should post financial
assurance may vary across projects. Requiring decommissioning surety prior to or upon energizing a
solar project offers localities immediate financial protection but also raises developers’ capital costs
considerably, particularly where a solar project has not yet begun creating revenue (Curtis et al.,
2021, “A Survey…”, p. viii). Pre-construction surety requirements may thus disincentivize developers
from offering proposals or lengthen the construction phase of approved projects (NYSERDA, 2020).
Surety posted at the power purchase agreement’s (PPA’s) expiration offers little long-term security to
localities lacking the legal protections of abandonment and liability clauses. Apart from a force
majeure event, it is extraordinarily unlikely that a solar facility with a PPA will cease operations during
the project life, thereby decreasing the risk of abandonment. Later-phase surety may make a county
or city relatively more competitive if it is seeking solar projects. Later posting further allows operators
the benefit of paying FA as an operating cost, rather than an initial capital cost (Curtis et al., 2021, p.
29). Intermediate posting options are described in greater detail below.
If a locality desires access to decommissioning security prior to the site’s construction, sufficient
assurance can be accessed by requiring the project owner to provide evidence of liability insurance
for the facility. This avoids levying a cost-prohibitive financial assurance condition—namely,
providing most or all of the FA before operation—on the developer while simultaneously protecting
the locality against site abandonment in the solar project’s early life. Note that liability insurance
differs from a risk-transfer policy.
Requiring a developer to post the most or all of the surety amount upon reaching the middle or first
third of the solar facility’s anticipated life allows the project owner to pay financial assurance as an
operating cost. This allows the locality to receive decommissioning security long before the facility’s
scheduled deactivation without threatening the project’s financial viability. For example, the City of
Suffolk requires the following financial assurance from Myrtle Solar Farm, LLC (15 MW):
"Beginning in year 10, the solar energy facility owner will obtain a letter of credit, bond, or such other security in an amount equal to the cost of performing the restoration obligations minus
the salvage value of the Solar Energy Facilities on the property."
A phased financial assurance approach may be similarly beneficial if the solar developer is a smaller
firm with less access to credit than a publicly regulated electric utility. Under this condition, the
project owner would post security to a cash escrow account or attain additional surety bonds or
letters of credit according to a pre-specified schedule. Depending on the locality’s preferences, a
developer may make constant or variable payments in regular intervals.
Decommissioning Utility-Scale Solar Facilities 39
For example, the conditional use permit approval for Twitty’s Creek Solar (13.8 MW) in Charlotte
County, Virginia outlays the following schedule of annual deposits to a reserve fund. Note that the
schedule below does not account for interest on the fund balance:
Operating Year Deposit Cumulative Fund
1 $40,900 $40,900 6.79%
2 $39,600 $80,500 13.37%
3 $37,400 $117,900 19.57%
4 $36,600 $154,500 25.65%
5 $37,400 $191,900 31.86%
6 $36,100 $228,000 37.85%
7 $35,300 $263,300 43.72%
8 $32,700 $296,000 49.14%
9 $30,000 $326,000 54.13%
10
11 $23,500 $376,500 62.51%
12 $20,500 $397,000 65.91%
13 $17,000 $414,000 68.74%
14 $13,900 $427,900 71.04%
15 to 30 $10,900 per
annum $602,300 by Year 30 100% by Year 30
Another phased FA approach is embodied in a proposed amendment to Pennsylvania Senate Bill 284
(S.B. 284 AO3939, 2022) at the time of this paper’s writing, which suggests the project owner should
post the estimated decommissioning cost in ten percent increments every five years, beginning thirty
days before the solar facility’s construction. Once the solar facility is established, the amendment
recommends the following conditions take effect:
Ten years after the initial security posting, the owner will provide 40% of the estimated decommissioning costs.
Fifteen years after the initial security posting, the owner will provide 60% of the estimated decommissioning cost less the facility’s salvage value, subject to the exception that the security
amount factoring salvage shall be no less than 40% of the estimated cost of decommissioning.
Decommissioning Utility-Scale Solar Facilities 40
Twenty years after the initial security posting, the owner will provide 80% of the estimated decommissioning cost less the facility’s salvage value, but the security amount factoring salvage
shall be no less than 60% of the estimated cost of decommissioning.
Twenty-five years after the initial security posting, the owner will provide 100% of the estimated
decommissioning cost less the facility’s salvage value, but the security amount factoring salvage shall be no less than 70% of the estimated cost of decommissioning.
These phased deposits provide the locality with the security of access to most of the
decommissioning surety prior to the project’s half-life without requiring steep commitments of
financial assurance from the developer early in the project.
Decommissioning Utility-Scale Solar Facilities 41
DETERMINING DECOMMISSIONING COSTS
A decommissioning cost estimate must be prepared or at least reviewed by a Virginia-licensed
engineer prior to submission to the locality’s Board of Supervisors, County Administrator, or other
relevant official (Va. Stat. §15.2-2241.2). To ensure that decommissioning costs reflect price changes
due to inflation and any non-uniform variation in costs among components of the decommissioning
process, many Virginia localities require periodic updates of the decommissioning cost estimate,
usually no less frequently than every ten years and no more frequently than every five years. The
Code of Virginia allows but does not mandate the inclusion of a salvage value, which may be
subtracted from the gross decommissioning cost to yield a net decommissioning cost estimate. In
any case, the decommissioning cost estimate applied by the locality cannot exceed the licensed
engineer’s projected cost of decommissioning (Va. Stat. §15.2-2241.2).
VALUATION OF THE ADMINISTRATIVE FACTOR
Some decommissioning ordinances and special use permit conditions apply an “administrative
factor” equaling ten to twenty-five percent of the gross decommissioning cost, or removal cost. The
administrative factor is added to the gross decommissioning cost and has several intended functions:
Section 2241.2 of the Code of Virginia allows localities to include “a reasonable allowance for the
estimated administrative costs related to a default of the owner, lessee, or developer [of a solar
facility]”. In specific cases where the Virginia Department of Transportation has notified the locality
that road damage is possible during site removal, the administrative factor assures that necessary
road improvements will occur in a timely manner without cost to the public. It also acts as a reserve
or buffer protecting the locality against any significant changes in the salvage credit claimed by the
developer.
Although the terms “administrative factor” and “inflation factor” are often used interchangeably, the
term “inflation factor” is misleading. Inflation, being any general changes in the prices of goods and
services throughout the economy, is naturally accounted for in the periodic re-calculation of the
decommissioning cost estimate. Non-inflationary, industry-specific changes in the prices of solar
hardware and the cost of decommissioning labor will also be fully accounted for in the re-calculation.
Requiring an inflation factor as allowed in Section 2241.2 of the Code of Virginia is only useful if the
decommissioning cost estimate is not regularly updated. If an annual inflation factor is preferred to a
periodic recalculation, the locality should apply the industrial inflation rate as published in the Bureau
of Labor Statistics’ producer price index (PPI).7
7 Author’s Note: The Bureau of Labor Statistics (BLS) regularly updates the PPI. Updates to the PPI
database can be accessed online at: https://www.bls.gov/ppi/databases/.
Decommissioning Utility-Scale Solar Facilities 42
The following statements exemplify superfluous special use permit conditions, and are not
recommended in cases where a professional engineer recalculates decommissioning costs at least
every five years:
“The decommissioning cost estimate must include a provision for inflation.”
“The decommissioning cost estimate shall be updated every five years from the date of approval and include the inflation rate as published by the Bureau of Labor Statistics, CPI.”
“The project owner’s decommissioning cost estimate shall be increased by twenty percent (20%) of said estimate costs as a reasonable allowance for administrative costs, inflation, and potential damage to existing roads or utilities during site removal.”
The following alternatives are both economically accurate and legally sound:
"The owner shall supply bond riders or replacement bonds, upon request by the Locality, to account for inflation and changes in anticipated costs.”
“The decommissioning plan shall be updated and filed with the County / City every five years to account for changed circumstances, including inflation.”
“The project owner’s decommissioning cost estimate shall be increased by twenty percent (20%) of said estimate costs as a reasonable allowance for administrative costs and potential damage to existing roads or utilities during site removal.”
SALVAGE CREDIT
Salvage Plan
The salvage plan is the portion of the decommissioning plan stating the description and quantities of
solar waste components that will be recycled, resold in a licensed secondary market, or landfilled. A
salvage plan should be prepared regardless of whether a locality factors salvage value. A project
owner should also report the salvage value, or residual value of recycled or resold hardware as
calculated by a Virginia-licensed engineer, alongside the decommissioning cost estimate even if the
locality does not allow a salvage credit equaling part or all of the salvage to be subtracted from the
decommissioning cost. Salvage values may change as the market for recycling and re-selling used
solar hardware continues to develop.
When to Allow a Salvage Credit
It is considered good practice for localities to factor salvage value by allowing a solar facility’s owner
or affiliate to subtract a salvage credit from the estimated cost of decommissioning, particularly as
recycling and resale markets for solar technologies grow more robust. Including a salvage credit
allows the project owner to post a lesser but sufficient financial assurance should the locality need to
take over system decommissioning.
Decommissioning Utility-Scale Solar Facilities 43
Localities can include a salvage credit while protecting against fluctuations in salvage value. This can
be broadly accomplished by applying a reserve in the decommissioning cost estimate to protect
against price volatility over the project life; for example, a locality may award a salvage credit by
reducing the estimated salvage value by twenty percent while increasing the gross cost estimate by
twenty percent (Maamari, 2018). The North Carolina Department of Environmental Quality similarly
recommends that a locality exclude a specific percentage of salvage value from the offset calculation
and revise it over time as recycling and reuse markets grow (2022, p. 12). To date, because salvage
value estimates are subject to considerable uncertainty, localities generally do not accept salvage
credit alone as sufficient decommissioning security in cases where the predicted salvage value
exceeds the decommissioning cost estimate. In every case, salvage value estimates should come
from an independent engineer rather than from a solar developer or facility owner.
Salvage Credit Calculations
Examples of salvage credit valuation from existing Virginia projects for which the salvage value
equals the estimated resale and recycling values associated with decommissioned equipment
include:
The salvage credit equals eighty percent of the salvage value. (CUP Approval, Eastern Shore Solar, Accomack County; CUP Approval, SunTec Solar, Accomack County; CUP Approval,
Southampton Solar, Southampton County)
The salvage credit equals ninety percent of the salvage value. (CUP Approval, Spring Grove Solar,
Surry County)
The salvage credit equals fifty percent of the salvage value. (Southampton County Code, §18-637)
Additional examples provided by the North Carolina Department of Environmental Quality suggest
the following salvage credit valuations:
125% of the estimated net cost of decommissioning established within the approved decommissioning plan, or 25% of the estimated decommissioning cost excluding salvage value, whichever is greater; or
1.25 times the estimated decommissioning cost minus the salvageable value; or
Either the difference of the estimated decommissioning cost and 50% of the salvageable value, or $75,000, whichever value is greater.
Decommissioning Utility-Scale Solar Facilities 44
SUMMARY OF RECOMMENDATIONS
The best practices for a locality to adopt when establishing regulations and financial assurance
options for utility-scale solar facilities will depend on the size and duration of the project, the
financial characteristics of the project developer, and the intended future use of the real property on
which the project is situated. Host localities should expect that specific details of their
decommissioning agreements with the developers of approved solar facilities will vary in accordance
with the context of each project. Key considerations to weigh across all projects include:
The local legal framework for utility-scale solar facilities;
If the locality has incorporated decommissioning regulations into its zoning ordinance, then any
subsequent decommissioning agreements and decommissioning plans are, at minimum, subject to
the requirements specified therein. Localities may wish to consider which legal mechanisms should
apply when determining whether a utility-scale solar facility should be repowered instead of
decommissioned.
A decommissioning ordinance—whether codified in the zoning ordinance or applied as a condition
for land use—should define “decommissioning” and “abandonment” to avoid legal ambiguity and
state the rights and rules of the locality regarding the decommissioning process. These rules may
include clauses enforcing the project owner’s legal liability for paying the costs associated with
removing and restoring the site, describing the conditions under which the locality would be allowed
to inspect the facility, and restating the locality’s right to enter and remove the facility without the
owner’s consent in the event of the owner’s failure to decommission. Emerging best practice is to
allow between twelve and twenty-four months of continuous inactivity before declaring a facility
abandoned, and to provide at least twelve months for decommissioning to be completed from the
time of the facility’s abandonment or end-of-life.
Specifying appropriate decommissioning plan contents;
In every case, it is prudent to require a decommissioning plan to state the project owner’s contact
information, the site’s anticipated project life, current land use, and proposed land use, a clearly-
explained calculation of the estimated present-value cost of decommissioning, a description of the
locality-approved financial assurance, a decommissioning narrative, a salvage plan—even in cases
where the locality does not factor a salvage credit—and a land restoration plan. It may be necessary
to include such measures as decompaction and soil restoration in the land restoration plan,
depending on the property owner’s intended future use for the land.
Decommissioning Utility-Scale Solar Facilities 45
Which financial assurance options are optimal to require of a developer;
Legally enforceable access to sufficient financial assurance (FA) to carry out decommissioning plays
an essential role in reducing the host locality’s risk of bearing the cost burden for removing a
deactivated solar facility and restoring the project site to an appropriate condition. Nationally,
localities tend to reject FA proposals that would substitute a salvage value estimate outweighing the
gross cost of decommissioning (i.e., a net gain from decommissioning) as sufficient decommissioning
security. Best practice provides that the surety amount be adjusted at least every five years based on
a Virginia-licensed engineer’s re-evaluation of decommissioning costs. Any salvage value estimate
could also be updated at this time. To maintain security in the event that a developer becomes
financially insolvent, localities should require FA to remain posted until all decommissioning
requirements have been fulfilled.
Trust funds, fully-funded or risk-transfer insurance policies, and cash escrow accounts should be used
with caution, as they may become prohibitively expensive for the facility owner. Surety bonds
generally provide localities the same level of financial assurance as letters of credit and cash escrow
accounts without affecting solar developers’ access to credit or working capital. If a project owner
can fulfill the capital requirements of a corporate financial test, parent guarantee, or promissory note,
localities should consider accepting such mechanisms as decommissioning security; in such case, the
locality will bear the administrative burden of verifying the information and business status provided
by the developer or its parent company.
To avoid delaying projects due to high capital costs or imposing undue financial hardship on the
solar developer, localities should consider requiring FA payments in phases or in the full amount
once the project is operational, rather than as a lump-sum during site development.
If and how inflation, administrative costs, and salvage values should be factored into the
decommissioning cost estimate.
Localities can account for inflationary changes in the decommissioning cost estimate by annually
applying an inflation factor to the original estimate. For a more precise assessment of
decommissioning costs, localities should instead have a Virginia-licensed engineer periodically
recalculate the decommissioning cost, no less frequently than every five years from the estimate’s
original filing with the locality. Based on emerging best practice, localities should also allow the
salvage value of solar equipment and site hardware—or, a salvage credit equaling a substantial
portion of the salvage value—to be subtracted from the gross decommissioning cost, as end-of-life
equipment will retain a resale value even where recycling streams do not exist. Salvage value
estimates should never come directly from a site owner or solar developer, but rather be prepared by
an independent engineer.
Decommissioning Utility-Scale Solar Facilities 46
Altogether, localities have ample discretion in determining and enforcing appropriate
decommissioning practices for utility-scale solar facilities in the Commonwealth of Virginia. The
principles and mechanisms detailed here are intended to provide localities with a helpful inventory of
regulatory options which can be tailored to the characteristics of the solar facilities they host.
Decommissioning Utility-Scale Solar Facilities 47
APPENDIX A: DECOMMISSIONING REGULATIONS BY
VIRGINIA LOCALITY, AS OF JULY 2022
As of July 2022, the following localities…
… Have neither a utility-scale solar decommissioning ordinance nor locally codified FA
requirements: Accomack County, Albemarle County, City of Alexandria, Arlington County, Bath
County, Bland County, Botetourt County, City of Bristol, Buchanan County, Buckingham County,
City of Buena Vista, Caroline County, Carroll County, Charles City County, City of Charlottesville,
Chesterfield County, City of Colonial Heights, City of Covington, Craig County, Cumberland
County, City of Danville, Dickenson County, City of Emporia, Essex County, City of Fairfax, Fairfax
County, City of Falls Church, Fauquier County, Floyd County, Fluvanna County, City of Franklin,
Franklin County, City of Fredericksburg, Galax City, Giles County, Goochland County, Grayson
County, Greene County, Greensville County, City of Hampton, Hanover County, Henrico County,
Decommissioning Utility-Scale Solar Facilities 48
City of Hopewell, James City County, King and Queen County, Lee County, City of Lexington,
Loudon County, Lunenburg County, City of Lynchburg, City of Manassas, City of Manassas Park,
City of Martinsville, Mathews County, Mecklenburg County, Nelson County, New Kent County,
City of Newport News, City of Norfolk, Northampton County, City of Norton, Nottoway County,
Orange County, Page County, Patrick County, City of Petersburg, City of Poquoson, City of
Portsmouth, Powhatan County, Prince William County, Pulaski County, City of Radford, City of
Richmond, City of Roanoke, Roanoke County, Rockbridge County, Russell County, City of Salem,
Scott County, Smyth County, Stafford County, City of Staunton, Tazewell County, City of Virginia
Beach, Warren County, City of Waynesboro, Westmoreland County, City of Williamsburg, City of
Winchester, Wise County.
… Have a utility-scale solar decommissioning ordinance, but no locally codified FA
requirements: Brunswick County, Clarke County, Frederick County, King George County,
Pittsylvania County, Rockingham County, Washington County, York County.
… Have both a utility-scale solar decommissioning ordinance and locally codified FA
requirements: Alleghany County, Amelia County, Amherst County, Appomattox County, Augusta
County, Campbell County, Charlotte County, City of Chesapeake, Dinwiddie County, Gloucester
County, Halifax County, Henry County, Highland County, Isle of Wight County, King William
County, Lancaster County, Louisa County, Middlesex County, Northumberland County, Prince
Edward County, Rappahannock County, Richmond County, Shenandoah County, Southampton
County, Spotsylvania County, City of Suffolk, Surry County.
… Have considered or are considering a drafted decommissioning ordinance with FA
requirements: City of Chesapeake (new FA requirements), Culpeper County, Prince George
County, Sussex County; Town of Wytheville has adopted a decommissioning ordinance with FA
requirements, but Wytheville County has not.
Decommissioning Utility-Scale Solar Facilities 49
APPENDIX B: DECOMMISSIONING CONSIDERATIONS
The following summary categorizes relevant options for localities to consider when creating
decommissioning guidelines for utility-scale solar facilities.
Key: Mandatory Enforcement Discretionary Enforcement
Continued on following page.
The locality grants zoning approval for a solar project, or receives an NOI for a by-right project.
State Laws
The following regulations (non-inclusive) apply:
Va. Stat. § 10.1-1197.6 (HB 206)
Va. Stat. §§15.2-2316.6:2316.9
Va. Stat. §15.2-2232
Va. Stat. §15.2-2241.2
Va. Stat. §§ 15.2-2288.7:2288.8
Va. Stat. § 45.2-1708
Va. Stat. §56-265.2
Va. Stat. §56-585.5 (VCEA)
Va. Stat. §62.1-44.15:51
9VAC-15-60-30:130
20VAC5-302-20
regulations codified in a local solar ordinance
and/or zoning ordinance.
Site-specific conditions attached to the siting
agreement and/or SUP, CUP, or SEP.
Per the terms of Va. Stat. §15.2.-2241.2,
project owner must enter into a written
agreement with the locality that it will
decommission the solar facility.
Decommissioning Utility-Scale Solar Facilities 50
(Continued on Next Page)
Administrative Factor:
Can be omitted. If
included, usually equals
between ten and
twenty-five percent of
the DCE.
What additional decommissioning measures should the locality consider?
When is a project deemed
“abandoned”?
What is the facility’s EoL?
What is the maximum
permissible timeframe for
decommissioning?
Can the facility owner file for
an extension on the
decommissioning process? If
so, what is the procedure for
approval?
Is the locality willing to
negotiate an extension on
the lease or use permit in the
event that a project can be
repowered upon EoL?
Decommissioning
Plan:
Contact
information
Anticipated
project life
Cost estimate
Decommissioning
narrative
Salvage plan
Restoration plan
Legal Protections for the Locality:
Clear definitions of “decommission”
and “abandonment”
Distinguish between periods of
continuous inactivity which do and do
not constitute abandonment
Entry rights
Owner’s liability for decommissioning.
Locality’s full access to
decommissioning financial assurance
upon abandonment or failure to
decommission in a timely manner
Procedure for local Notice, exceptions,
and extensions on decommissioning
Temporary variance framework
How should decommissioning costs be calculated?
Decommissioning Cost Estimate (DCE):
Must be prepared by an independent,
Virginia-licensed engineer.
OR
inflation
annually with
an inflation
factor, based on
PPI published
for inflation
and industry
changes by
recalculating
the DCE every
Salvage Credit:
Best practice is to factor
part or all of the salvage
value. Not required under
current state law. Never
accept directly from the
developer; should always
be calculated by an
independent engineer.
Should be recalculated
every 5 to 10 years.
Decommissioning Utility-Scale Solar Facilities 51
What financial assurance (FA) mechanisms should the locality consider?
Use with Caution:
Can become prohibitively expensive for the facility
owner to post or maintain.
Trust fund (p. 28)
Fully-funded insurance policy (pp. 31-32)
Risk-transfer insurance policy (pp. 31-32)
Cash escrow account (pp. 28-29)
Considered Infeasible at Present:
Salvage value alone, where salvage value
exceeds decommissioning cost estimate.
Pooled funds (p. 35)
Decommissioning insurance pool (p. 36)
Accessible for Many Facility Owners:
Letter of Credit (pp. 29-30)
Decommissioning Surety Bond (pp. 30-31)
Accessible for Well-Capitalized Facility Owners:
Parent Guarantee (p. 35)
Promissory Note (p. 35)
Corporate Financial Test (pp. 33-34)
When should the locality require the facility owner to post FA?
FA should always cover the full cost of decommissioning and should always be posted until decommissioning
is complete.
A lump-sum payment of the full decommissioning cost estimate during site construction can cause project delays.
FA payments in a predetermined phased schedule, or in the full amount once a project is operational are less
likely to impose undue financial hardship on the facility owner.
Decommissioning Utility-Scale Solar Facilities 52
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