Tag: renewable energy

Good News for Offshore Wind Blows in With New Guidance From the Treasury and IRS

The Inflation Reduction Act of 2022 (IRA) includes several tax credits to encourage investment in renewable energy projects, including an Investment Tax Credit (ITC) that is worth up to 30% of the overall project cost. The developer of a renewable energy project can receive a bonus of up to 10% on top of the ITC for a qualified facility that is located or placed in service in an “energy community.” One type of area that can qualify as an energy community under the IRA — the one most relevant to offshore wind projects — is an area that has significant employment or local tax revenues from fossil fuels and a higher-than-average unemployment rate.

In order to apply the criteria to offshore wind facilities, the US Department of Treasury initially proposed that an offshore wind project would be deemed to be located or placed in service at the place closest to the point of interconnection (POI) where there is land-based equipment that conditions the energy generated by the offshore wind project for transmission, distribution, or use.

Stakeholders in the offshore wind industry believed, however, that this approach did not adequately reflect the original intent of the IRA as it neglected to take into account the long-term benefits of activity related to offshore wind projects at locations, particularly ports, that were not at the POI.

Responding to stakeholder advocacy over the past several months, on March 22, the Internal Revenue Service (IRS) released updated guidance in IRS Notice 2024-30 (the Notice). The Notice permits projects with multiple POIs to qualify for the bonus credit, so long as one of the POIs is within an energy community. Stakeholders believe that this will be key in developing the shared transmission infrastructure that will be required for effective use of offshore wind energy.

Further, the Notice permits offshore wind facilities to attribute their nameplate capacity to additional property — namely, to supervisory control and data acquisition system (SCADA) equipment owned by the owner of the offshore wind project and located in an EC Project Port (as defined in the Notice). SCADA equipment is property that is used to remotely monitor and control the operations of the offshore wind project. The SCADA system is effectively the nerve center for an offshore wind project.

An “EC Project Port” is defined in the Notice as a port that is used either full or part time to facilitate maritime operations necessary for the installation or operation and maintenance of the offshore wind project, and that has a significant long-term relationship with the project’s owner by virtue of ownership or lease arrangements. The personnel based at the port need to include staff who are employed by, or who work as independent contractors for, the project’s owner and who perform functions essential to the project’s operations. Staff based at the port will be considered to perform functions essential to the project’s operations only if they collectively perform all the following functions: management of marine operations, inventory and handling of spare parts and consumables, and berthing and dispatch of operation and maintenance vessels and associated crews and technicians.

Finally, the Notice adds two industry codes from the North American Industry Classification System (NAICS) to those that are used to determine a community meets the IRA’s required percentage of its workforce who are employed in the extraction, processing, transport, or storage of coal, oil, or natural gas. These additional NAICS codes designate oil pipeline infrastructure and natural gas distribution infrastructure. These additional codes are intended to bring the benefits of the energy community bonus credit to more communities and the IRS has amended its list of energy communities accordingly.

Advocates note that the updated guidance in the Notice represents a more holistic approach to the energy communities bonus credit that will give offshore wind project developers more flexibility in identifying ports for their investment, The increased flexibility will bring the economic benefit of the offshore wind industry to more communities, which will ultimately reduce the cost burden to ratepayers.

© 2024 Jones Walker LLP
For more news on Tax Credits for Renewable Energy, visit the NLR Tax section.

Taking Stock of a Big Month for Methane Policy

November has been a big month for methane policy, featuring announcements of new international, domestic, and private sector initiatives.  A common thread across all of the new initiatives is the aim of achieving more ambitious, credible, and internationally consistent standards for measurement, monitoring, reporting, and verification (MMRV) of methane emissions from the oil and gas sector.  Below is a review.

China’s Methane Pledge.  China is the world’s largest emitter of methane, accounting for 14% of the global total, and, for the first time, the government made an international announcement about methane policy.  At a November summit held in Sunnylands, California, President Joe Biden and Chinese President Xi Jinping announced a new agreement to address climate change. Previous Chinese pledges had only targeted carbon dioxide, but the new agreement includes a first-ever commitment by the country to tackle non-CO2 emissions, including methane.  Just prior to the Sunnylands summit, the Chinese government issued an action plan outlining goals to curb flaring and to develop a methane MMRV program.

EU Methane Regulation.  The European Union (EU) also broke new ground on methane policy this month.  After all-night talks, the EU’s governing entities finalized a new Methane Regulation, which targets not only domestic sources of methane but also emissions attributable to imports of natural gas into the Continent—including from the United States. For imports, the Regulation establishes phased requirements.  The first phase focuses on data collection coupled with a mechanism for detecting and rapidly addressing large leaks.  The second phase will condition imports on application of prescribed, uniform MMRV measures.  Starting in 2030, importers will be subject to a limit on their methane “intensity”—a metric that measures methane emissions per unit of gas throughput.  The methane intensity limit will apply across the entire value chain, from pre-production through final delivery.  The Regulation requires the EU Commission to promulgate the intensity standard by 2027.

International Working Group on MMRV for Natural Gas Markets.  To support not only these emerging governmental policies but also expanding private sector efforts to create a market for “Differentiated Gas,” a multilateral initiative was announced in November—the International Working Group to Establish a Greenhouse Gas Supply Chain Emissions Measurement, Monitoring, Reporting, and Verification (MMRV) Framework for Providing Comparable and Reliable Information to Natural Gas Market Participants (the Working Group). The Working Group’s members consist of the U.S. government, eleven other governments, the European Commission, and the Mediterranean Gas Forum.  The Working Group’s objective is to develop a consensus-based, consistent international framework for supply chain MMRV.  A consistent framework will make it easier for buyers to demand and suppliers to provide natural gas with a lower greenhouse gas profile.  The Working Group will not prescribe emission targets, but it acknowledges that governments may use its work products to inform regulatory processes.

The Working Group has stated that it will draw on input from expert stakeholders.  To that end, a consortium of three universities participating in the Energy Emissions Modeling and Data Lab (EEMDL) has convened a group of academic, think tanks, ENGO, and market experts to develop recommendations for MMRV standards for the Differentiated Gas market. (I am a participating expert in the EEMDL initiative.)  This month, a subset of the experts group published a paper in Nature Energy outlining the issues.

Financial Institutions Call for Industry Action.  Underscoring the increasing private sector demand for Differentiated Gas, two major financial institutions released reports in November calling for industry action.  JP Morgan, one of the world’s largest financiers of fossil fuel projects, issued a report underscoring its commitment to achieve a net zero-aligned emission intensity reduction target for its oil and gas sector portfolio. Methane reductions are a key element of its net-zero strategy.  To that end, the report identifies and exhorts the industry to adopt best-in-class practices for methane MMRV and mitigation.

In the same week, one of the world’s largest insurance underwriters for the oil and gas sector, Chubb, rolled out a Methane Resource Hub, a digital resource center for its clients. The site provides information on MMRV and mitigation techniques, technologies, studies, and policies.

Waiting for EPA.  Also expected in November is EPA’s proposed implementation rules for the “Methane Fee” that was enacted as part of the Inflation Reduction Act (IRA).  The IRA provisions apply a per-ton fee to facilities in the oil and gas sector that exceed specified methane intensity limits.  To implement the fee, EPA will need to promulgate methods for facility-level methane intensity measurements.  A significant issue in the rulemaking is the extent to which EPA will allow affected facilities to use advanced methane measurement technologies to calculate their annual emissions.

© 2023 Van Ness Feldman LLP
For more news on methane policy, visit the NLR Environmental, Energy & Resources section.

Renewable Energy Tax Credit Transfer Guidance Provides Both Clarity And Pitfalls

Highlights

The renewable tax credit transfer market will accelerate with new government guidance; public hearing and comments deadlines are scheduled for August

Risk allocation puts the usual premium on sponsors with a balance sheet and/or recapture insurance coverage

While the guidelines provide clear rules and examples, many foot faults are present

On June 14, 2023, the Treasury Department and Internal Revenue Service issued long-awaited guidance on the transferability of certain renewable energy-related federal tax credits. The guidance takes the form of a notice of proposed rulemaking, proposed regulations, and an online Q&A, with a public hearing to follow in August.

Under new Code Section 6418, eligible taxpayers can elect to transfer all or any specified portion of eligible tax credits to one or more unrelated buyers for cash consideration. While the tax credits can be sold to more than one buyer, subsequent transfers by the buyer are prohibited.

This alert highlights several practical issues raised by the guidance, which should allow participants waiting for more clarity to proceed.

Individual Buyers Left Out

  • The guidance applies the Code Section 49 at risk rules and Section 50(b) tax-exempt use rules, generally restricting sellers in calculating the amount of tax credits for sale, and Code Section 469 passive activity rules, generally restricting buyer’s use of such tax credits, in various contexts. On the buyer side, these rules appear to be more restrictive than the limitations that would apply to identical tax credits in an allocation, rather than sale, context. Suffice to say, this will prohibit individuals from taking part in the transfer market for practical purposes outside of fact patterns of very limited application.
  • While this result may not be surprising since such rules currently severely restrict individuals from participating in traditional federal tax credit equity structures, there was some hope for a different outcome due to the stated policy goal of increasing renewable energy investment (not to mention the Inflation Reduction Act’s general departure from decades of case law precedent and IRS enforcement action prohibiting sales of federal tax credits with the enactment of Section 6418).

Lessees Cannot Sell the Tax Credits

  • A lessee cannot transfer the credit. With the prevalence of the master lease (inverted lease) structure in tax equity transactions, this prohibition created an unexpected roadblock for deal participants who have been structuring tax equity transactions with backstop type sale provisions for almost a year now. This presents developers, at least in the inverted lease context, with a choice of utilizing a traditional tax equity structure for the purpose of obtaining a tax-free step up in basis to fair market value, or forgoing the step up for less financing but also less structure complexity. The standard partnership flip project sale into a tax equity type of holding company structure could still remain a viable alternative.
  • As the transfer is generally made on a property-by-property basis by election, creative structuring, in theory, could allow for a lessor to retain certain property and sell the related tax credits (e.g., on portfolios with more than one solar installation/project, or even with large projects that go online on a block-by-block basis assuming the “energy project” election is not made – a term that future guidance will need to provide more clarity on).
  • However, this seems to be an ivory tower conclusion currently, and the practical reality is that too many unknown issues could be raised by such out of the box structuring, including the fact that conservative institutional investors may refuse to participate in such a structure until clear objective guidance is published addressing the same.

Bonus Credits Cannot Be Sold Separately

  • Bonus credits cannot be sold separately from the underlying base credit. This is more problematic for certain adders – for example, the energy community adder rules are now out and amount to simply checking a location on a website. Others (e.g., the low-income community or domestic content adder) require more extensive and subjective application and qualification procedures which makes when and how such adders can be transferred difficult to ascertain. Projects hoping to transfer such credits may need to be creative in compensating buyers for such uncertainty and qualification risk. Tax equity transactions that closed prior to the guidance’s issuance may also need to be revisited, as provisions in such transaction documents commonly attempted to bifurcate the bonus credit away from the base credit in order to allow the sponsor to separately sell such adders.

Buyers Bear Recapture Risk and Due Diligence Emphasis

  • While the Joint Committee on Taxation Bluebook indicated the buyer is responsible for recapture, industry participants were still hoping such risk would remain with the seller. Outside of the limited situation of indirect partnership dispositions (which still results in a recapture event to the transferring partner if triggered), the recapture risk is borne by the buyer, using the rationale that the buyer is the “taxpayer” for purposes of the transferred tax credits. While this is familiar territory for tax equity investors, whose allocated tax credits would be reduced in a recapture scenario, tax credit purchase transactions are now burdened with what amounts to the standard tax equity type of due diligence, including negotiation of transaction documents outside of a basic purchase agreement.
  • The guidance provides that indemnity protections between the seller and buyer are permitted. Tax equity transactions historically have had robust indemnification provisions, which should remain the case even more so in purchase/sale transactions. Tax equity investors traditionally bear “structure risk” dealing with whether the investor is a partner for tax purposes – such risk is eliminated in the purchase scenario as the purchasing investor no longer needs to be a partner (subject to the caveat of a buyer partnership discussed below).
  • If the buyer claims a larger credit amount than the seller could have, such “excessive credit transfer” will subject the buyer to a 20 percent penalty on the excess amount (in addition to the regular tax owed). All buyers are aggregated and treated as one for this purpose – if the seller retains any tax credits, the disallowance is first applied to the seller’s retained tax credits. A facts and circumstances reasonable cause exception to avoid this penalty is provided, further emphasizing the need for robust due diligence.
  • Specific non-exclusive examples that may demonstrate reasonable cause include reviewing the seller’s records with respect to determining the tax credit amount, and reasonable reliance on third-party expert reports and representations from the seller. While not unique to this new tax credit transfer regime, the subjective and circular nature of such a standard is complex – for example, when is it not “reasonable” for buyers or other professionals to rely on other board certified and licensed professionals, such as an appraiser or independent engineer with specialized knowledge?
  • Buyers thus need to remain vigilant about potential recapture causing events. For example, tax equity investors will not generally allow project level debt on investment tax credit transactions without some sort of lender forbearance agreement that provides that the lender will not cause a tax credit recapture event (such as foreclosing and taking direct ownership of the project). Buyers remain responsible for such a direct project level recapture event, which again aligns the tax credit transfer regime with tax equity due diligence and third-party negotiation requirements. The guidance is more lenient for the common back-leverage debt scenario.
  • While similar interparty agreements between back leverage lenders and the tax equity investor are required for non-project level debt facilities to address tax credit recapture among other issues, the guidance provides that a partner disposing of its indirect interest in the project (e.g., the lender foreclosing and taking ownership of a partner’s partnership interest) will remain subject to the recapture liability rather than the buyer provided that other tax-exempt use rules are not otherwise implicated. However, the need to negotiate such lender related agreements is still implicated as not all recapture risk in even this scenario was eliminated to the buyer.
  • While the recapture risk could place a premium on production tax credit deals (that are technically not subject to recapture or subjective basis risk), the burdensome process of needing to buy such tax credits on a yearly basis in line with sales of output may make such transactions more tedious.
  • The insurance industry already has products in place to alleviate buyer concerns, but this is just another transaction cost in what may be a tight pricing market. Not unlike tax equity transactions, sponsor sellers with a balance sheet to backstop indemnities may be able to demand a pricing premium; other sponsors may need to compensate buyers with lower credit pricing to reward such risk and or/to allow the purchase of recapture insurance. While this seems logical, the guidance also includes anti-abuse type rules whereby low credit pricing could be questioned in terms of whether some sort of impermissible transfer by way of other than cash occurred (e.g., a barter for some sort of other service). What the IRS subjectively views as “below market” pricing could trigger some sort of audit review based on this factor alone which further stresses the importance of appropriate due diligence.

Partnerships and Syndications

  • The guidance provides very clear rules with helpful examples, which should allow partnership sellers and buyers to proceed with very objective parameters. For example, the rules allow a partnership seller to specify which partner’s otherwise allocable share of tax credits is being sold and how to then allocate the tax-exempt income generated. The cash generated from sales can be used or distributed however the partnership chooses.
  • Similar objective rules and examples are provided for a buyer partnership. Subsequent direct and indirect allocations of a purchased tax credit do not violate the one-time transfer prohibition. Purchased tax credits are treated as “extraordinary items” that must be allocated among the partners of the buyer partnership as of the time of the transfer, which is generally deemed to occur on the first date a cash payment is made. Thus, all partners need to be in the partnership on such date to avoid an issue. Purchased tax credits are then allocated to the partners in accordance with their share of the nondeductible expenditures used to fund the purchase price.
  • What level of end-user comfort is needed in such a syndicated buyer partnership is an open question. While the rules provide objective guidelines in terms of when and how such purchased credits are allocated, subjective questions that are present in (and focused on) traditional tax equity partnerships are implicated. For example, could a syndication partnership set up for the business purpose of what amounts to selling the tax credits somehow run afoul of the subjective business purpose and disguised sale rules in tax credit case precedent, such as the Virginia Historic Tax Credit Fund state tax credit line of precedent? Will the market require a robust tax opinion in such scenario, thereby driving up transaction costs?
  • An example in the proposed regulations speaks to this sort of partnership formed for the specific purpose of buying tax credits, but leaves out of the fact pattern a syndicator partner. The example itself should go a long way towards blessing such arrangements, but the IRS taking a contrary position when dealing with such issues would not be a new situation. For example, the IRS challenged allocations of federal historic tax credits as prohibited sales of federal tax credits to the point of freezing the entire tax equity market with its positions in Historic Boardwalk Hall, which was only rectified with the release of a subsequent safe harbor revenue procedure.
  • Moreover, the guidance provides that tax credit brokers are allowed to participate in the market so long as the tax credits are not transferred to such brokers as an initial first step in the transfer process (as the subsequent transfer to an end user would violate the one-time transfer rule). Specifically, at no point can the federal “income tax ownership” be transferred to a broker. It is an open question if further distinction will be made at where this ownership line should be drawn. For example, can a third party enter into a purchase agreement with a seller and then transfer such rights prior to the transfer election being made? Does it matter under such analysis if 1) purchase price installments have been paid (which implicates rules in the buyer partnership context as noted above) and/or 2) the tax credit generating eligible property has been placed in service (which is when the investment tax credit vests for an allocated tax credit analysis; a production tax credit generally arises as electricity or the applicable source is sold)?
  • Indirectly implicated is what effect the new transfer rules will have on established case law precedent and IRS enforcement action in traditional tax equity structures. The Inflation Reduction Act and guidance dances around certain of these issues by creating a fiction where the buyer is treated as the “taxpayer” – this avoids the issue of turning a federal tax credit into “property” that can be sold similar to a certificated state tax credit. This also provides a more logical explanation as to why the buyer of these federal tax credits does not need to report any price discount as income when utilized, unlike the well-established federal tax treatment of certificated state tax credits that provides the exact opposite (e.g., a buyer of a certificated state tax credit at $0.90 has to report $0.10 of income on use of such tax credit).

Other Administrative and Foot-Fault Issues

  • The purchase price can only be paid in cash during the period commencing with the beginning of the seller’s tax year during which the applicable tax credit is generated and ending on the due date for filing the seller’s tax return with extensions. Thus, such period could be as long as 21.5 months or more (e.g., a calendar year partnership seller extending its return to Sept. 15). Tax equity transactions generally have pricing timing adjusters for failure to meet placement in service deadlines. Such mechanism will not work if advanced payments were made and then the project’s projected placement in service year changes. Tax credit purchase agreements executed prior to the June 14 guidance may require amendments or complete unwinds to line up with the rules to avoid foot faults (e.g., purchase agreements executed in 2022 where a portion of the purchase price was paid in 2022 for anticipated 2023 tax credits would not fall within the “paid in cash” safe harbor period). Advanced commitments, so long as cash is not transferred outside of the period outlined above, are permitted.
  • The typical solar equity contribution schedule of 20 percent at a project’s mechanical completion makes purchase price schedules approximating the same a reasonable adjustment for most investment tax credit energy deals in terms of the timing of financing. In addition, the advance commitment blessing of the guidance will give lender parties the comfort necessary similar to having executed tax equity documents in place. Thus, typical project construction financing mechanisms should be similar in the tax equity versus purchase agreement scenario, with projects that allow for a more delayed funding mechanism possibly obtaining a tax credit pricing premium. Production tax credit deals, for which tax credits can only be paid for on a yearly basis within the cash paid safe harbor timing window, may have more significant project financing hurdles without further tax credit transfer rule modifications.
  • Sellers can only make the transfer election on an original return, which includes extensions. Buyers, by contrast, may claim the purchased tax credit on an amended return.
  • Buyers need to be aware that usage of the purchased tax credits is tied to the tax year of the seller. For example, a fiscal year seller could cause the tax credits to be available a year later than an uninformed buyer anticipated, regardless of when the tax credit was generated using a traditional placement in service analysis. For example, a solar project placed in service during November 2023 by an August fiscal year seller would generate credits first able to be used in a calendar year buyer’s 2024, instead of 2023, tax year. A buyer can use the tax credits it intends to purchase against its estimated tax liability.
  • The pre-registration requirements, which are expansive and open-ended, are also tied to the taxable year the tax credits are generated and generally must be made on a property-by-property basis. For example, 50 rooftop installations could require 50 separate registration numbers outside of the “energy project” election. When such registration information needs updated is also not entirely clear – for example, a project is often sold into a tax equity partnership syndication structure on or before mechanical completion. Needing to update registration information could delay transactions and implicates unknown audit risk.

While these rules provide much-needed clarity, failure to adhere may be catastrophic and will require sellers and buyers to put proper administrative procedures in place to avoid foot faults. The new transfer regime will expand the market to new buyers who may have viewed tax equity as either too complex or had other reasons to avoid these transactions, such as the accounting treatment of energy tax credit structures. However, it would be prudent for such buyers to approach such transactions with eyes wide open.

© 2023 BARNES & THORNBURG LLP

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Renewable Energy Tax Credits under the Inflation Reduction Act: Opportunities for Exempt Organizations

The Inflation Reduction Act of 2022 (the “IRA” or “Act”) added and modified several renewable energy tax provisions under the Internal Revenue Code of 1986, as amended (the “IRC”).[1] These changes provide many opportunities for exempt organizations, investors, and developers in clean energy projects to lower their costs by monetizing previously unavailable tax credits and thereby increase their business. Among them:

  • Solar facilities are now eligible for the Section 45 Production Tax Credit
  • An Investment Tax Credit for stand-alone energy storage technology with a minimum capacity of 5 kWh
  • A new two-tier credit system consisting of a base credit and an additional bonus credit for eligible projects that satisfy new prevailing wage and apprenticeship requirements
  • New “domestic content,” “energy community,” and “low-income community” bonus credits
  • New “technology neutral” tax credits
  • New ways to monetize tax credits

There has been significant interest in the energy credits by tax exempt organizations, in particular by universities and hospitals. Indeed, these organizations have been looking to minimize their greenhouse gas impact or carbon footprint with the goal of achieving clean energy even prior to the enactment of the IRA. The direct pay option which is now available under the IRA has accelerated the interest in clean energy. Commentators also note that private foundations have been interested in addressing climate change and taking advantage of these newly enacted credits to help spread the use of clean technologies.

Section 6417, discussed below, could be a “game changer” in this regard. Even though certain of the credits have been in existence, unless tax exempts have had a significant amount of unrelated business income tax (“UBIT”), they previously could not avail themselves of the credits prior to the enactment of Section 6417 which provides the direct payment alternative.

The below will outline the new and modified renewable energy tax credits under the IRA, and summarize recent guidance issued by the Treasury Department.

CHANGES TO EXISTING TAX CREDITS

Section 45 Production Tax Credit

Before the enactment of the IRA, the Section 45 Production Tax Credit (“PTC”) was available to electricity produced from certain renewable resources, including wind, biomass, geothermal, hydropower, municipal solid waste, and marine and hydrokinetic energy. Under the Act, solar facilities and are now also eligible for the PTC. In order to qualify for the PTC, eligible facilities must be placed in service and start construction before the end of 2024. Facilities which begin construction after December 31, 2024, will fall under the new technology-neutral tax credit regimes (discussed below).

Section 48 Investment Tax Credit[2]

Prior to the Act, the Section 48 Investment Tax Credit (“ITC”) was not available to stand-alone energy storage projects. The IRA created an ITC for stand-alone energy storage technology with a minimum capacity of 5 kWh. The term “energy storage technology” includes any technology that receives, stores, and delivers energy for conversion to electricity, or to most technology that thermally stores energy.

Like the PTC, under the Act, eligible facilities can qualify for the ITC as long as they are placed in service and begin construction before the end of 2024. Facilities which begin construction after December 31, 2024, will fall under the new technology-neutral tax credit regimes (discussed below).

STRUCTURAL CHANGES TO THE TAX CREDIT SYSTEM

The IRA created a new two-tier credit system consisting of a base credit and an additional bonus credit that is only available for eligible projects that satisfy the new prevailing wage and apprenticeship requirements (discussed below). The new ITC base rate will be 6 percent, and the bonus rate will increase it to 30 percent. The new PTC base rate will be 0.3 cents/kwh and the bonus rate will increase it to 1.5 cents/kwh.

Prevailing Wage Requirement

Taxpayers must pay laborers, mechanics, contractors, and subcontractors a prevailing wage during the construction of the project and with respect to subsequent alterations or repairs of the project following its placement in service. The prevailing wage is based on the pay rates published by the Department of Labor (“DOL”) for the geographic areas and type of job or labor classification. If relevant pay rates are not published, the taxpayer must request a wage determination or wage rate from the DOL.[3]

Apprenticeship Requirement

Taxpayers must also ensure that, with respect to the construction of a qualified facility, no fewer than the “applicable percentage” of total labor hours are performed by qualified apprentices. The “applicable percentage” is: (i) 10 percent for projects beginning construction before 2023, (ii) 12.5 percent for projects beginning construction during 2023, and (iii) 15 percent for projects beginning construction thereafter. Each contractor and subcontractor who employs four or more individuals to perform construction on an applicable project must employ at least one qualified apprentice. A “qualified apprentice” is an individual who is employed by the taxpayer or any contractor or subcontractor and who is participating in a registered apprenticeship program.

If a taxpayer fails to satisfy the apprenticeship requirement during a particular year, the taxpayer may correct the failure by paying a penalty to the IRS equal to $50 ($500 if the apprenticeship requirement was intentionally disregarded) multiplied by the total number of labor hours that did not satisfy the apprenticeship requirement. However, the IRA also includes a “good faith effort” exception if the taxpayer requests qualified apprenticeships from a registered apprenticeship program and either the request is denied, or the program fails to respond within five business days after receiving the request.

ADDITIONAL BONUS CREDITS

The IRA established the “domestic content,” “energy community,” and “low-income community” bonus credits.

Domestic Content

Projects qualifying for certain PTC and ITC credits could qualify for a 10 percent increase to the base and bonus credits if they satisfy the IRA’s new “domestic content” requirements. To qualify for this bonus credit, all steel, iron, and manufactured products that are components of the completed facility are to be produced in the United States.

Energy Community

Facilities located in an “energy community” will also qualify for a 10 percent increase to the base and bonus credits. An “energy community” includes brownfield sites, certain areas with significant employment related to, or local tax revenues generated by, coal, oil, or natural gas, and where there is high unemployment, or a census tract where a coal mine has recently closed or a coal-fired electric plant was retired or removed.

NEW “TECHNOLOGY NEUTRAL” TAX CREDITS

The IRA added new tax credits that apply to qualified facilities placed into service after December 31, 2024, and which yield zero greenhouse gas emissions. The Section 45Y Clean Electricity Production Credit (“CEPTC”) and the Section 48E Clean Electricity Investment Credit (“CEITC”) will replace the PTC and ITC, respectively, and are intended to be technology neutral. The credit amounts for the CEPTC and CEITC are calculated similarly to the PTC and ITC and are subject to similar prevailing wage and apprenticeship bonus requirements.

NEW WAYS TO MONETIZE TAX CREDITS UNDER THE IRA

The Act established the following two novel methods to monetize energy tax credits.

Direct Pay Available to Tax Exempt Organizations

For tax years beginning after December 31, 2022, and before January 1, 2033, certain “applicable entities” can make an election to receive a cash payment equal to the value of otherwise allowable tax credits. This option allows for the applicable entities to utilize and monetize the tax credits via a refund, even though the entities generally do not incur tax liabilities. The term “applicable entities” includes tax-exempt organizations, state and local governments, tribal governments, and the Tennessee Valley Authority.

The direct pay option is also available to taxpayers claiming the Sections 45V, 45Q, and 45X credits even if they do not meet the definition of an “applicable entity.”

Third-Party Sales

For tax years beginning after December 31, 2022, taxpayers (“transferee”) that do not meet the definition of an “applicable entity” may transfer all or a part of their eligible credits to an unrelated taxpayer (“transferor”) in exchange for cash. The cash consideration is not includible in the income of the transferor and is not deductible by the transferee. Credits may not be transferred more than once. In the case of any transfer election, the transferee taxpayer will be treated as the taxpayer for all purposes under the IRC with respect to such credit. With respect to a project held by a partnership, only the partnership itself (and not its partners) can elect to transfer the eligible credits. (Emphasis added.) Then it is likely to be treated as unrelated trade or business.

All of the tax credits eligible for the direct pay option, except for the Section 45W Clean Commercial Vehicles Credit, are also eligible for sale to a third-party.

NOTICES 2023-17 AND 2023-18

On February 13, 2023, the IRS issued Notices 2023-17 and 2023-18 which provide guidance on the administration of two allocation-based renewables tax credit programs under Sections 48(e) and 48C, respectively.

Notice 2023-17

The Act amended Section 48(e) to provide an increase in the ITC for qualified solar and wind facilities which are deployed in specified low-income communities or residential developments. To receive these increased credit amounts, a taxpayer must receive an allocation of “environmental justice solar and wind capacity limitation” (“Capacity Limitation”). A “qualified solar and wind facility” is any facility that (1) generates electricity solely from a wind facility, solar energy property, or small wind energy property; (2) has a maximum net output of less than five megawatts (as measured in alternating current); and (3) is described in at least one of the four categories described in the chart below.

Notice 2023-17 established the Low-Income Communities Bonus Credit Program under Section 48(e) and provided guidance on the procedures and information required to apply for an allocation of Capacity Limitation. For each of 2023 and 2024, the annual capacity limitation is 1.8 gigawatts of direct current capacity, which will be allocated among four categories of projects as follows:

Category

Required Facility Location

Category

Required Facility Location

Capacity Limitation Allocation (MW)

Bonus Percentage

1

Low-Income Community

700 MW

10%

2

Indian Land

200 MW

10%

3

Qualified Low-Income Residential Building Project

200 MW

10%

4

Qualified Low-Income Economic Benefit Project

700 MW

10%

A taxpayer must submit an application to the IRS in order to receive a Capacity Limitation allocation. Details regarding the application process are forthcoming, however, Notice 2023-17 states that applications will be accepted in a phased approach during a 60-day application window for calendar year 2023. Applications will be accepted for Category 3 and 4 projects beginning in the third quarter of 2023, and Category 1 and 2 project applications will be accepted thereafter.

The Department of Energy (“DOE”) will review applications for statutory eligibility and any other criteria provided by the IRS. On this basis, the DOE will provide recommendations to the IRS regarding the selection of applicants for an allocation of Capacity Limitation. If the selected applications exceed the capacity limitations for a given category, the DOE will use a lottery system or some other process to allocate Capacity Limitations. If accepted, the IRS will notify the applicant of its decision and specify the amount of Capacity Limitation allocated. Within four years of receiving such notification applicants must place the eligible property in service to claim the increased credit rate.

Notice 2023-18

The Act extended the Section 48C Advanced Energy Project Credit (“48C Credit” or “AEPC”), which was originally enacted as part of the American Recovery and Reinvestment Act of 2009. Section 48C provides a credit for investments in projects that fall into one of the following three general categories: (i) clean energy manufacturing and recycling projects, (ii) greenhouse gas emission reduction projects, and (iii) critical materials projects. The AEPC is subject to an aggregate cap of $10 billion, at least $4 billion of which will be allocated to census tracts (or tracts adjacent to census tracts) in which coal mines have been closed after 1999 or coal-fired generation facilities have been retired after 2009.

Notice 2023-18 provides guidance on the process and timeline for applying for an allocation of 48C Credits. The first allocation round of $4 billion began on May 31, 2023. Outlined below is an overview of the application, review, and approval process for the first allocation round of 48C credits:

The applicant submits a “concept paper” to the DOE between May 31, 2023, and July 31, 2023.

After reviewing the concept paper, the DOE will issue a letter to the applicant either encouraging or discouraging the submission of an application. All applicants that submit a concept paper during the above period may submit an application irrespective of the DOE’s response.

The applicant submits an application to the DOE for review. If the applicant intends to apply for a bonus credit because it will satisfy the prevailing wage and apprenticeship requirements, it must confirm this in the application.

The DOE then makes a recommendation as to whether to accept or reject the application and provides a ranking of the applications.

Based on the DOE’s recommendations and rankings, the IRS will make a decision regarding the acceptance or rejection of the application and notify the applicant of its decision.

Within two years after receiving an allocation from the IRS, the applicant must provide evidence to the DOE that the certification requirements have been met.

The DOE notifies the applicant and the IRS that it has received the applicant’s notification that the certification requirements have been met.

The IRS will provide a letter to the applicant certifying the project (“Allocation Letter”).

Within two years after receiving the Allocation Letter, the applicant must notify the DOE that the project has been placed in service. The applicant may claim the 48C Credit in the year in which the property is placed in service.

Additional guidance from the Treasury Department and IRS is expected to be released throughout the year.

FOOTNOTES

[1] Unless otherwise stated, all “Section” references are to the IRC.

[2] For any investment tax credit under Section 50(b)(3), an exempt organization could only avail itself of such credit to the extent the property in question was used in unrelated business income. So in effect, prior to the enactment of IRA, any property that was used consistent with the tax exempt organization’s mission presented an obstacle which Section 6417 expressly overrides. Section 50(b)(3).

[3] If a taxpayer fails to meet the prevailing wage requirement during a particular year, the taxpayer may cure the failure by paying each worker the difference between actual wages paid and the prevailing wage, plus interest and a penalty of $5,000. If a taxpayer’s failure to pay prevailing wages was due to “intentional disregard,” then the taxpayer must pay each worker three times the difference and pay the IRS a $10,000 penalty per worker.

© 2023 Blank Rome LLP

For more tax news, click here to visit the National Law Review.

U.S. Department of Transportation Finalizes EV Charging Infrastructure Rules

Effective as of March 30, 2023, the Federal Highway Administration (“FHWA”) within the U.S. Department of Transportation (“DOT”) announced the National Electric Vehicle Infrastructure Standards and Requirements final rule  (the “Final Rule”) (23 CFR 680).  The Final Rule included several significant updates to the Notice of Proposed Rulemaking published on June 9, 2022 which we summarized in our prior article. These updates function to establish a set of minimum standards and requirements for electric vehicle (“EV”) charging infrastructure projects funded with federal dollars from the Bipartisan Infrastructure Law (“BIL”), and with these updates in place, interested parties will have certainty with respect to NEVI-funded projects.1

The key updates included in the Final Rule are located in the following sections:

  1. Installation, operation, and maintenance by qualified technicians of EV infrastructure (§ 680.106)

  2. Interoperability of EV charging infrastructure (§ 680.108)

  3. Data requested related to a project funded under the NEVI Formula Program, including the format and schedule for the submission of such data (§ 680.112)

  4. Network connectivity of EV charging infrastructure (§ 680.114)

  5. Information on publicly available EV charging infrastructure locations, pricing, real-time availability, and accessibility though mapping applications. (§ 680.116)

Installation and Operation

The Final Rule contains modified language clarifying that any time charging stations are installed, there must be a minimum of four (4) ports, notwithstanding the type of port–including Direct Current Fast Charger (“DCFC”) and AC Level 2 chargers. Additionally, charging stations may also have non-proprietary connectors. This modification allows permanently attached non-proprietary connectors to be provided on each charging port so long as each DCFC charging ports have at least one permanently attached CCS type 1 connector and is capable of charging a CCS compliant vehicle.  These modifications will allow for increased accessibility to owners of all types of electric vehicles.

Concerned commenters expressed distain toward the Notice of Proposed Rulemaking for lack of clarity on whether the Final Rule would apply to the NEVI formula program, Title 23, and publicly accessible EV chargers funded as a project on a federal aid highway. The FHWA responded in the Final Rule with modified language to confirm its applicability across these programs. To address concerns about opposition to the rule as applied to Title 23 projects, the language in the Final Rule was revised to provide increased flexibility in the use of funds to install different types of chargers, including for projects not located along Alternative Fuel Corridors and installing AC Level 2 charges and DCFCs at lower power levels. Additionally, AC Level 2 charger capability was modified to incorporate the ability to charge at 208-volt.

The Final Rule also reevaluated and modified charging capacity. Modifications require that each DCFW must simultaneously deliver up to 150 kW. Additionally, each AC level 2 port is required to have the capability of providing at least 6 kW, however, the customer has the option to accept a lower power level to allow power sharing or to participate in smart charge management programs. Smart charge management involves controlling charging power levels in response to external conditions and is typically applied in situations where EVs are connected to charges for long periods of time, such that prolonging charging for the benefit of the grid is not objectionable to charging customers. In contrast, power sharing involves dynamically curtailing power levels of charging ports based on the total power demand of all EVs concurrently charging at the same station. Power sharing is permissible above the minimum per-port requirements for DCFC and AC Level 2 chargers. Further, each DCFC port must support output voltage with a permitted range between 250 and 920 volts. This all allows for greater flexibility to manage the cost of the stations designed to meet current and future demand for increases in power, given the strong market trend towards EV charging power capacity above 150 kW for DCFC and above 6 kW for AC Level 2 charging.

The Notice of Proposed Rulemaking required charging stations to remain open for 24 hours, but commenters believed this requirement did not present a realistic standard nationwide. In the Final Rule, the language was amended to allow for less restrictive charging hours for charging stations located off designated AFCs and requires that the charging station must be available for use at least as frequently as the business operating hours of the site host, with discretion to the site host to allow longer access.

Payment and Price Transparency

Payment and Price Transparency received both modification and expansion under the Final Rule. State programs may allow for certain charging stations to be free, and as such, language in the Final Rule was modified to specify that payment mechanisms may be omitted from charging stations if charging is provided for free. Regarding acceptable payment methods, the Final Rule explicitly incorporated payment by mobile application in the “contactless payment methods” definition. Further, the Final Rule modified acceptable payment methods to include an automated toll-free calling or an SMS option as an additional payment method. While there is no guarantee that every individual will have access or the ability to speak on the phone or send a text, the FHWA sees this addition as a step in the right direction to help bridge the accessibility gap in access and payment for EV charging.

The Final Rule also altered price transparency to require that the dollar per kWh be transparently communicated prior to initiating a charge, and that other fees be clearly explained prior to payment.

Charging Station Information, Data Sharing, and Interoperability of EV Charging Infrastructure

The Final Rule also modified uptime requirements. The uptimes calculations were clarified by modifying the definition of when a charger is considered “up” and further modifying the equation to calculate uptime to the nearest minute to make the calculation more uniform across all charging station operators and network providers.

Open Charge Point Protocol (“OCPP”) and ISO 15118 are key components of interoperability. OCPP is an open source communication standard for EV charging stations and networks, and ISO 15118 is hardware that specifies the communication between EVs including Battery Electric Vehicles and Plug-In Hybrid Electric Vehicles, and the Electric Vehicle Supply Equipment. In the Final Rule, the FHWA discussed that OCPP version 2.01 has significant improvements over previous versions and contains compelling benefits to the EV charging ecosystem. As such, the Final Rule contains modifications regarding the charger-to-charger network requiring that charging networks conform to the newer OCPP version 2.01 by one year after the date of publication of the Final Rule in the Federal Register. Additionally, FHWA requires charging station conformance to ISO 15118 and Plug and Charge capability by one year after the date of publication of the Final Rule in the Federal Register. Although many chargers on the market today are not yet using ISO 15118, the FHWA sees value in establishing a national standard for compliance. .

Annual data submittal, quarterly, and one time submittal requirements were modified to be completely streamlined and requiring any data made public to be aggregated and anonymized to protect confidential business information. The Joint Office of Energy and Transportation will establish and manage a national database and analytics platform that will streamline submission of data from States and their contractors along with providing ongoing technical assistance to States.

The Final Rule removed interoperability requirements and instead requires that chargers remain functional even if communication with the charging network is temporarily disrupted.

Community Engagement

For NEVI formula program projects, community engagement outcomes were modified in the Final Rule to require inclusion in the annual state EV infrastructure deployment plan rather than a separate report. This will allow for the type of information and data from the States to be most beneficial for informing and improving community engagement. Though we will have to wait until release of the annual Plan guidance to receive details regarding content expectations, commenters suggested several ways the report could be developed, including (i) conditioning funding for future years on meeting robust engagement requirements, including community engagement and equity and inclusion efforts by States (ii) describing how community engagement informed station and siting operations (iii) describing how workforce opportunities were integrated into community engagement efforts; and (iv) describing engagement with disabled community members.

The Future of EV Infrastructure

We will quickly see the significant effects the Final Rule will have on customers and manufacturers alike in enhancing EV charging capacity across the United States in this rapidly changing and ever-growing sector. As regulators, developers, and financiers of EV infrastructure evaluate the Final Rule, the Foley team is at the ready with significant experience, knowledge and expertise related to each element of this transformation, including issues related to the automotive, manufacturing, supply chain, regulatory, IP, private equity, tax equity, project finance, and public-private financing issues.

© 2023 Foley & Lardner LLP

For more Environmental Law News, click here to visit the National Law Review.

FOOTNOTES

1 For a summary of the NEVI Formula Program, refer to our February 2022 article linked here.

Relief Arrives for Renewable Energy Industry – Inflation Reduction Act of 2022

On August 12, 2022, Congress passed the Inflation Reduction Act of 2022 (“Act” or “IRA”), a $400 billion legislative package containing significant tax and other governmental incentives for the energy industry, in particular the renewable energy industry. The bill will have an immediate impact on the wind and solar industries, along with other clean energy projects and businesses.

SUMMARY

The IRA is a slimmed down substitute for the Build Back Better bill resulting from a compromise with Senator Joe Manchin (D-WV), whose support was necessary for the bill to pass the Senate.

The IRA comes as welcome news to the renewable energy industry as important tax incentives for wind, solar and other renewable energy resources are set to expire or wind down. Existing law also did not provide any federal tax incentives for the rapidly growing stand-alone energy storage and clean hydrogen industries.

The IRA fixes that, and more. The Act extends the investment tax credit (ITC) for solar, geothermal, biogas, fuel cells, waste energy recovery, combined heat and power, small wind property, and microturbine and microgrid property for projects beginning construction before January 1, 2025. It also extends the production tax credit (PTC) for wind, biomass, geothermal, solar (which previously expired at the end of 2005), landfill gas, municipal solid waste, qualified hydropower, and marine and hydrokinetic resources for projects beginning construction before January 1, 2025. The IRA also allows taxpayers to include their interconnection costs as part of their eligible basis for the ITC.

The Act now allows the ITC to be taken for stand-alone energy storage (previously storage was only allowed an ITC if it was part of another project, e.g., solar). Other technologies are also benefitted from the IRA, including carbon capture and sequestration (CCS) (tax credit extended and modified), clean hydrogen (a new credit of up to $3.00 per kilogram of clean hydrogen produced), nuclear power (a new credit of up to 1.5c/kWh) and biofuel (existing credit extended).

The ITC and PTC now come with strings attached. To qualify for the restored 30% ITC and the 2.6c/kWh PTC (adjusted for inflation), projects must pay prevailing wages during construction and the first five years (in the case of the ITC) and 10 years (in the case of the PTC) of operation, while also meeting registered apprenticeship requirements. Projects that fail to satisfy the prevailing wage and apprenticeship requirements will only receive an ITC of 6% or a PTC of .3c/kWh (adjusted for inflation). The prevailing wage and apprenticeship requirements apply to employees of contractors and subcontractors as well as the company. These requirements are effective for projects that begin construction 60 days after the IRS issues additional guidance on this issue. Certain exceptions apply, including for certain small (less than 1 MW) facilities.

On the flip side, the Act includes enhancements that, in the case of the ITC, can increase the credit percentage if a project satisfies certain additional criteria. Bonuses are available for projects that (1) satisfy certain U.S. domestic content requirements (10%) or (2) are located in an “energy community” (10%) or an “environmental justice” area (10% or 20%). An “energy community” is defined as a brownfield site, an area which has or had significant employment related to oil, gas, or coal activities, or a census tract or any adjoining tract in which a coal mine closed after December 31, 1999, or in which a coal-fired electric power plant was retired after December 31, 2009. An “environmental justice” area is a low-income community or Native American land (defined in the Energy Policy Act of 1992) (10%) or a low-income residential building or qualified low-income economic benefit project (20%).

The Act also creates two new methods for monetizing the ITC, PTC, and certain other credits. Tax-exempt organizations will be permitted to elect a “direct pay” option in lieu of a tax credit. In a dramatic change that may have substantial impacts on renewable project finance, the Act permits most taxpayers to transfer the ITC, PTC, and certain other tax credits for cash.

For the first time, the Act includes a tax credit, known as the Advanced Manufacturing Production Credit, for companies manufacturing clean energy equipment in the U.S. such as PV cells, PV wafers, solar grade polysilicon, solar modules, wind energy components, torque tubes, structural fasteners, electrode active materials, battery cells, battery modules, and critical minerals.

The Act also contains major tax incentives, in the form of credits and enhanced deductions to spur electric and hydrogen-fueled vehicles, alternative fuel refueling stations, nuclear power, energy efficiency, biofuels, carbon sequestration and clean hydrogen. Additional grants are available for interregional and offshore wind and electricity transmission projects, including for interconnecting offshore wind farms to the transmission grid.

Additional detail regarding these provisions follow below.

KEY ENERGY PROVISIONS OF THE INFLATION REDUCTION ACT OF 2022

Investment Tax Credit (ITC)

The ITC is extended for projects beginning construction prior to January 1, 2025. The ITC starts at a base rate of 6%. The ITC increases to 30% if a project (1) pays prevailing wages during the construction phase and for the first five years of operation and (2) meets registered apprenticeship requirements. The ITC applies to solar, fuel cells, waste energy recovery, geothermal, combined heat and power, and small wind property, and is now expanded to include stand-alone energy storage projects (including thermal energy storage), qualified biogas projects such as landfill gas, electrochromic glass, and microgrid controllers. For microturbine property the base rate is 2%, which increases to 10% if the prevailing wage and apprenticeship requirements are met.

Projects under one megawatt (AC) and projects that begin construction prior to 60 days after the Secretary of the Treasury publishes guidance on the wage and registered apprenticeship requirements do not have to meet the prevailing wage and apprenticeship requirements to qualify for the 30% ITC.

PREVAILING WAGE REQUIREMENT

The new prevailing wage requirement is intended to ensure that laborers and mechanics employed by the project company and its contractors and subcontractors for the construction, alteration or repair of qualifying projects are paid no less than prevailing rates for similar work in the locality where the facility is located. The prevailing rate will be determined by the most recent rates published by the U. S. Secretary of Labor. Prevailing wages for the area must be paid during construction and for the first five years of operation for repairs or alterations once the project is placed in service. Failure to satisfy the standard will result in a significant penalty, including an 80% reduction in the ITC (i.e., an ITC of 6%), remittance of the wage shortfall to the underpaid employee(s) and a $5,000 penalty per failure. For intentional disregard of the requirement the penalty increases to three times the wage shortfall and $10,000 penalty per employee.

The prevailing wage requirement takes effect for projects that begin construction after December 31, 2022, but not before 60 days after the Secretary publishes its guidance. Projects under 1 MW (AC) are exempt from the requirement.

APPRENTICESHIP REQUIREMENT

For projects with four or more employees, work on the project by contractors and subcontractors must be performed by qualified apprentices for the “applicable percentage” of the total number of labor hours. A qualified apprentice is an employee who participates in an apprenticeship program under the National Apprenticeship Act. The applicable percentage of labor hours phases in and is equal to 10% of the total labor hours for projects that begin construction in 2022, 12.5% for projects beginning construction in 2023, and 15% thereafter. Similar penalties to the prevailing wage penalties apply for failure to satisfy the apprenticeship requirement. A “good faith” exception applies where an employer attempts but cannot find apprentices in the project’s locality.

The apprenticeship requirement takes effect for projects that begin construction after December 31, 2022, but not before 60 days after the Secretary publishes its relevant guidance. Projects under 1 MW (AC) are exempt from the requirement.

Credit Enhancements

Domestic Content. Assuming a project meets the prevailing wage and apprenticeship requirements, a qualifying project can earn a 10% ITC bonus (i.e., bringing the ITC to 40%), if it satisfies the domestic content requirement. To satisfy the domestic content requirement a project must use 100% U.S. steel and iron, and an “adjusted percentage” of the total costs of its manufactured components with products that are mined, produced or manufactured in the U.S. The applicable percentage for projects other than for offshore wind facilities initially is set at 40%, increasing to 45% in 2025, 50% in 2026, and 55% in 2027. For offshore wind facilities the adjusted percentage initially is 20%, and phases up to 27.5% in 2025, 35% in 2026, 45% in 2027, and 55% in 2028 and after. The initial domestic content bonus for projects failing to meet the prevailing wage and apprenticeship requirement is 2%, which percentage similarly phases up.

Two exceptions exist to the domestic content requirement: (1) if the facility is less than 1 MW (AC) and (2) if satisfying the requirement will increase the overall cost of construction by more than 25 percent, or if the relevant products are not produced in the U.S. in sufficient and reasonably available quantities or quality. Under these circumstances, the unavailability of the product is counted 100% against the adjusted percentage, that is, the adjusted percentage is calculated as if 100% U.S. content was supplied for the unavailable items.

The domestic content bonus is only available for projects placed in service after December 31, 2022.

Energy Community Bonus. A project can earn an additional 10% ITC bonus if it is built in an energy community. An energy community is defined as (a) a brownfield site (as defined under CERCLA), (b) an area that has or had significant employment related to the coal, oil, or gas industry and has an unemployment rate at or above the national average, or (c) a census tract or adjoining tract in which a coal mine closed after December 31, 1999 or a coal-fired electric power plant was retired after December 31, 2009.

The Energy Community Bonus is only available for projects placed in service after January 1, 2023.

Environmental Justice. An additional 10% and, in some cases, 20% ITC bonus, is available for solar and wind projects of 5 MW AC or less where the project is located in, or services, a low-income community. The environmental justice bonus is limited to a maximum of 1.8 gigawatts of solar and wind capacity in each of calendar years 2023 and 2024, for which a project must receive an allocation from the U.S. Treasury Secretary. The 10% bonus is for projects located in a low-income community or on Native American land (defined in the Energy Policy Act of 1992). The 20% bonus is available for projects that are part of a qualified low-income residential building project or a qualified low-income economic benefit project. A qualified low-income residential project is a residential rental building that participates in a housing program such as those covered under the Violence Against Women Act of 1994, a housing assistance program administered by the Department of Agriculture under the Housing Act of 1949, a housing program administered under the Native American Housing Assistance and Self-Determination Act of 1996, or similar affordable housing programs. A qualified low-income economic benefit project is one where at least 50% of the households have income at less than 200% of the poverty line or at less than 80% of the area’s median gross income.

Storage projects installed in connection with a solar project also qualify for the environmental justice bonus, but not stand-alone storage projects. A project receiving an allocation for the environmental justice credit must be placed in service within four years of the date it receives the allocation.

Stand-Alone Storage. The Act now provides a tax credit for stand-alone energy storage projects. To qualify, the storage project must be capable of receiving, storing and delivering electrical energy and have a nameplate capacity of at least 5 kWh. Thermal storage projects and hydrogen storage projects qualify under the new provision. Like the ITC for other technologies, the base ITC for stand-alone storage is 6%, and increases to 30% for projects that satisfy the prevailing wage and apprenticeship requirements or if they are placed into service prior to 60 days after the Treasury Secretary issues guidance on prevailing wage and apprenticeship standards.

Interconnection Equipment. Qualifying projects under 5 MW (AC) now may claim an ITC on their interconnection costs. The credit applies even if the interconnection facilities are owned by the interconnecting utility, so long as they were paid for by the taxpayer. This is not a stand-alone tax credit, but rather an additional cost added to a project’s basis eligible for the ITC.

Production Tax Credit (PTC)

The Act extends the production tax credit (PTC) for projects beginning construction before January 1, 2025. The PTC is set at an initial Base Rate of .3c/kwh. Like the ITC, the credit increases to 1.5c/kwh for projects satisfying the prevailing wage and apprenticeship requirements. The 1.5 c/kWh, with the inflationary adjustment provided for the PTC, brings the PTC up to 2.6c/kWh in 2022. In addition to wind projects, the PTC is available to solar, closed-loop and open-loop biomass, geothermal, landfill gas, municipal solid waste, qualifying hydropower, and marine and hydrokinetic facilities. Thus, solar projects may now choose either the PTC or the ITC. They cannot receive both.

CREDIT ENHANCEMENTS

Like the ITC, a project can receive an enhanced PTC similar in degree to those under the ITC for satisfying the domestic content, energy community and/or environmental justice requirements. For projects meeting the prevailing wage and apprenticeship requirements the increase for each applicable bonus is generally 10% of the underlying credit and, for projects failing to satisfy those requirements, 2%.

Clean Electricity Investment Tax Credit

The Act creates a new clean electricity tax credit (ITC and PTC) that replaces the existing ITC and PTC once they phase out at the end of 2024. The successor ITC/PTC is technology neutral. Any project producing electricity can qualify for the tax credit if its greenhouse gas emissions rate is not greater than zero. The successor ITC is 30% and the PTC is 1.5c/kWh, escalated annually with inflation. The Clean Energy ITC/PTC will phase out the later of 2032 or when emission targets are achieved (i.e., the electric power sector emits 75% less carbon than 2022 levels). Once the target is reached, facilities will be able to claim a credit at 100% value in the first year, then 75%, then 50%, and then 0%.

Clean Hydrogen Production Credit

This Act for the first time provides a tax credit for qualifying clean hydrogen projects. The credit is available for clean hydrogen produced at a qualifying facility during the facility’s first 10 years of operation. The base credit amount is $0.60 per kilogram (kg) times the “applicable percentage,” adjusted annually for inflation. For projects meeting the prevailing wage and apprenticeship requirements the credit amount is five times that base amount, or $3.00/kg times the applicable percentage, adjusted annually for inflation.

The applicable percentage for hydrogen projects achieving a lifecycle greenhouse gas emissions rate of less than 0.45 kilograms of carbon dioxide equivalent (CO2e) per kg is 100%. The applicable percentage falls to 33.4% for hydrogen projects with an emissions rate between .45kg and 1.5kg, and to 25% for hydrogen projects with an emissions rate between 1.5 kg and 2.5 kg. For hydrogen projects with a lifecycle greenhouse gas emissions rate between 4 kg and 2.5 kg of CO2e per kg, the applicable percentage is 20%.

To qualify for the credit, the facility must begin construction before January 1, 2033. Facilities existing before January 1, 2023 can qualify for a credit based on the date that modifications to their facility required to produce clean hydrogen are placed into service. Taxpayers may also claim the PTC for electricity produced from renewable resources by the taxpayer if the electricity is used at a clean hydrogen facility to produce qualified clean hydrogen. The Direct Pay option, discussed below, is available for clean hydrogen projects.

Taxpayers can elect to claim the ITC in lieu of the clean hydrogen production credit. However, taxpayers claiming the clean hydrogen credit cannot also claim a tax credit for carbon capture under Section 45Q, and vice versa.

Carbon Capture and Sequestration (CCS) Credit

Under prior law, industrial carbon capture or direct air capture (DAC) facilities that began construction by December 31, 2025, could qualify for the Section 45Q tax credit for carbon oxide sequestration. This credit could be claimed for carbon oxide captured during the 12-year period following the facility being placed in service. The per metric ton tax credit for geologically sequestered carbon oxide was set to increase to $50 per ton by 2026 ($35 per ton for carbon oxide that is reused, such as for enhanced oil recovery) and adjusted for inflation thereafter.

The Act extends the deadline for construction to January 1, 2033 and increases the credit amount. The base credit amount for CCS is $17 per metric ton for carbon oxide that is captured and geologically sequestered, and $12 per metric ton for carbon oxide that is reused. For facilities that meet the prevailing wage and apprenticeship requirements during construction and for the first 12 years of operation, the credit amounts are $85 per ton and $60 per ton, respectively.

The credit amount for carbon oxide captured using DAC and geologically sequestered is also increased under the Act to a base rate of $36 per metric ton, and to $180 per metric ton for projects that meet prevailing wage and apprenticeship requirements. The rates are indexed for inflation beginning in 2026.

The Act reduces the minimum plant size required to qualify for the credit:  from 100,000 to 1,000 tons per year for DAC; from 500,000 to 18,750 metric tons per year for electric generating facilities paired with qualifying CCS equipment, and from 25,000 to 12,500 metric tons per year for any other facility. A CCS project paired with an electric generating unit will be required to capture at least 75% of unit (not facility) CO2 production.

Advanced Energy Project Credit

The Act provides a 30% credit for investments in projects that re-equip, expend, or establish certain domestic manufacturing or industrial facilities to support the production or recycling of renewable energy property. Examples of such facilities include those producing or recycling components for:

  • Energy storage systems and components;
  • Grid modernization equipment or components;
  • Equipment designed to remove, use, or sequester carbon oxide emissions;
  • Equipment designed to refine, electrolyze, or blend any fuel, chemical, or product which is renewable or low-carbon and low-emission;
  • Property designed to produce energy conservation technologies (residential, commercial and industrial);
  • Electric or fuel-cell vehicles, including for charging and refueling infrastructure;
  • Hybrid vehicles weighing less than 14,000 pounds and associated technologies, components, or materials;
  • Re-equipping industrial and manufacturing facilities to reduce their greenhouse gas emissions by at least 20%;
  • Re-equipping, expanding, or establishing an industrial facility for the processing, refining or recycling of critical materials.

Projects not satisfying the prevailing wage and apprenticeship requirements will only receive the base ITC credit of 6%.

The Act makes $10 billion available for qualifying advanced energy projects. Of that amount, at least $4 billion must be allocated to projects located in energy communities. The Treasury Secretary will establish a program to award credits to qualifying advanced energy projects. Applicants awarded credits will have two years to place the property in service. The provision goes into effect on January 1, 2023.

Advanced Manufacturing Production

The Act creates a new production tax credit that can be claimed for the domestic production and sale of qualifying solar and wind components, such as inverters, battery components and critical minerals needed to produce these components.

Credits for solar components include:

  • for thin film photovoltaic cell or crystalline photovoltaic cell, 4 cents per DC watt of capacity;
  • for photovoltaic wafers, $12 per square meter;
  • for solar grade polysilicon, $3 per kilogram;
  • for polymeric backsheet, 40 cents per square meter; and
  • for solar modules, 7 cents per DC watt of capacity.

For wind energy components, if the component is an offshore wind vessel, the credit is equal to 10% of the sales price of the vessel. Otherwise, the credits for various wind components vary as set forth below, which amount is multiplied by the total rated capacity of the completed wind turbine on a per watt basis for which the component is designed.

The applicable amounts for wind energy components are:

  • 2 cents for blades
  • 5 cents for nacelles
  • 3 cents for towers
  • 2 cents for fixed platform offshore wind foundations
  • 4 cents for floating platform offshore wind foundations
  • for torque tubes and longitudinal purlin, $0.87 per kg
  • for structural fasteners, $2.28 per kg
  • for inverters, the credit is an amount multiplied by the inverter’s AC capacity, with different types of inverters eligible for specified credit amounts ranging from 1.5 cents to 11 cents per watt
  • for electrode active materials, the credit is 10% of the production cost
  • for battery cells the credit is $35 per kilowatt hour of battery cell capacity. Battery modules qualify for a credit of $10 per kilowatt hour of capacity (or $45 in the case of a battery module which does not use battery cells).

A 10% credit is also available for the production of critical minerals. Critical minerals include aluminum, antimony, barite, beryllium, cerium, cesium, chromium, cobalt, dysprosium, europium, fluorspar, gadolinium, germanium, graphite, indium, lithium, manganese, neodymium, nickel, niobium, tellurium, tin, tungsten, vanadium and yttrium.

For purposes of the credits for battery cells and modules, to qualify the capacity-to-power ratio cannot exceed 100:1. The term ‘capacity-to-power ratio’ means the ratio of the capacity of the cell or module to the maximum discharge amount of the cell or module.

The advanced manufacturing credit phases out for components sold after December 31, 2029. Components sold in 2030 are eligible for 75% of the full credit amount. Components sold in 2031 and 2032 are eligible for 50% and 25% of the full credit amount, respectively. No credit is available for components sold after December 31, 2032. The phase-out does not apply to the production of critical minerals.

DIRECT PAY

The Act contains a valuable cash payment option that allows certain organizations to treat certain tax credit amounts including, among others, the ITC, PTC, clean hydrogen, and carbon capture credits, as payments of tax and then receive a refund for that tax that is deemed paid. Under the so-called “direct pay” option, in lieu of receiving a tax credit, an eligible entity will be treated as if it had paid taxes in the amount of the credit, for which it can then receive a cash refund. Entities eligible for the direct pay option include tax-exempt organizations, state and local governments, Indian tribes (as defined in the Act), the Tennessee Valley Authority, and any Alaska Native Corporation. The direct pay option is subject to an annual election and must be claimed by a partnership or S corporation rather than its partners or S corporation shareholders. Refunds under the direct pay provisions are treated the same as tax credits for purposes of basis reduction, depreciation rules, and recapture.

For qualifying facilities electing direct pay that do not meet the domestic content requirements, a reduction applies for projects beginning construction in 2024 (90%) and 2025 (85%). Thereafter, the direct pay option will not be available for projects that do not satisfy the domestic content requirement.

TRANSFERRABLE CREDITS

The IRA allows eligible taxpayers that do not elect the direct pay option to transfer certain credits to unrelated taxpayers including, among others, the ITC, PTC, clean hydrogen, and carbon capture credits. The transferred credit must be exchanged for cash. Credits may only be transferred once. Carryforwards or carrybacks are not transferable. Payments made to the transferor of the credit are not taxable to the transferor, nor is the payment by the transferee to the transferor deductible to the transferee.

The credit period for transferred credits is 23 years (including three years for carrybacks). The credit must be used in earliest possible year of transferee. A 20% penalty may apply for both direct payments and transfers where excessive payments have occurred.

Zero Emission Nuclear Power Production Credit

The Act includes a new PTC for the production of electricity from an existing nuclear facility that was placed in service before the date of enactment of the Act. To qualify, the electricity from the facility must be produced and sold to an unrelated person after December 31, 2023. The credit terminates on December 31, 2032. The base PTC amount is 3 cents per kWh, but is increased five times if wage and apprenticeship requirements are met (to 1.5 cents per kWh), in each case adjusted annually for inflation and reduced by a reduction amount to the extent electricity from the plant is sold at a price over $0.025/kWh.

Electric Vehicles and Hydrogen-Fueled Cars

The Act includes a $7,500 credit for taxpayers purchasing new electric vehicles and a $4,500 tax credit for used ones. The Act eliminates the previous “per-manufacturer” limits that applied to the new vehicle credit, but imposes new domestic content and assembly requirements, as well as caps on the retail price of new vehicles, and the income of the taxpayers purchasing the vehicle.

The Act also sets aside financing and credits to promote electric vehicle manufacturing. It calls for $2 billion in grants to help convert existing auto manufacturing factories into ones that make electric vehicles and $20 billion of loans for new clean vehicle manufacturing facilities. The Act extends the credits to hydrogen-fueled cars in addition to EVs.

Alternative Fuel Refueling Property Credit

The Act revives the expired credit for alternative fuel refueling property (i.e., electric vehicle chargers), allowing it for property placed in service before December 31, 2032. The base credit is 6% of the cost of property, and is increased to 30% if wage and apprenticeship requirements are met. The previous $30,000 cap is also increased to $100,000.

OFFSHORE WIND

The IRA puts in place a 10-year window in which a lease for offshore wind development cannot be issued unless an oil and gas lease sale has also been held in the year prior and is not less than 60 million acres. The Act also withdraws the Trump administration’s moratorium on offshore wind leasing in the southeastern U.S. and eastern Gulf of Mexico.

GREEN BANK

The Act includes $27 billion toward a clean energy technology accelerator to support deployment of emission-reduction technologies, especially in disadvantaged communities. The EPA Administrator would be permitted to disburse $20 billion to “eligible recipients,” which are defined as non-profit green banks that “provide capital, including by leveraging private capital, and other forms of financial assistance for the rapid deployment of low- and zero-emission products, technologies, and services.

Clean Fuel Production Credit

The Act creates a new tax credit for domestic clean fuel production starting in 2025 and expires for transportation fuels sold after December 31, 2027. The tax credit is calculated as the applicable amount multiplied by the emissions factor of the fuel. The base credit is $0.20 per gallon of transportation fuel produced at a qualified facility and sold, which increases to $1.00 if prevailing wage requirements are met. The base credit is $0.35/gallon for sustainable aviation fuel, $1.75 if labor and wage requirements are satisfied. The emissions factor of the fuel may reduce the credit amount. The credits are adjusted for inflation. The credit cannot be claimed if other clean fuel credits are claimed, including clean hydrogen production.

Article By Kris J. Eimicke and Merrill Kramer of Pierce Atwood LLP

For more energy and environmental legal news, click here to visit the National Law Review.

©2022 Pierce Atwood LLP. All rights reserved.

The SEC’s Proposed Rules on Climate-Related Disclosures – What to Do Now: A Guide for In-House Counsel Facing the Proposed Rules

The U.S. Securities and Exchange Commission’s recently proposed rules governing climate-related disclosures, if adopted as proposed, would represent a sea change to the existing public-company disclosure regime.  The rules would require that public companies include the following, among other disclosures, in reports and registration statements filed with the SEC:

  • disclosure of greenhouse gas (GHG) emissions data covering Scope 1 and Scope 2 emissions for all companies and Scope 3 emissions for companies1 (other than those that qualify as “smaller reporting companies”) for which Scope 3 emissions are material or that have set emissions reduction targets that include Scope 3 emissions, with third-party attestation being required for Scope 1 and Scope 2 data for companies that qualify as “large accelerated filers” or “accelerated filers”;
  • extensive and detailed disclosures regarding climate-related risks, including physical risks and transition-related risks, to a company’s financial statements, business operations or value chain (i.e., upstream and downstream activities of third parties related to the company’s operations);
  • disclosure in the notes to audited financial statements of quantitative and qualitative information regarding financial impacts of climate-related risk, including disaggregated quantitative information with respect to impacts of physical risks or transition activities on specific financial statement line items if the impact is 1% or more of the line item;
  • extensive and detailed disclosures regarding climate-related governance, strategy and risk management; and
  • to the extent relevant to a particular company, disclosures regarding the company’s transition plan, climate-related targets or goals, use of scenario analyses or other analytical tools in evaluating climate-related risk and use of an internal carbon price.

For many companies, the rules would require enterprise-wide changes to how the company collects, assesses and reports climate-related data and other information, as well as changes to their governance structures and systems of controls.  Changes may be driven both by the need to comply with the disclosure requirements and by a company’s view of how its disclosures will be received by investors or the public generally.

The tasks of understanding the implications of the proposed rules for a particular company and preparing for eventually complying with the rules are monumental, and, unfortunately, public companies currently find themselves in the difficult position of possibly needing to act with some urgency in order to be prepared to comply with rules of uncertain substance on an uncertain timeline.  At this point, the proposed rules are just that – proposed and not final.  The period for public comment on the proposed rules will run until May 20 at the earliest and could be extended by the SEC, and public comments are likely to reflect the controversial nature of the proposed rules and strong opinions by both supporters and detractors.  After the comment period, whether and when the SEC releases final rules, and the extent to which any final rules largely follow or reflect significant changes from the proposed rules, will remain to be seen.  Like the proposed rules, any final rules should provide for phase-in periods for compliance.  Further, any final rules are almost certain to face legal challenges that could delay implementation of the rules even if such challenges ultimately are unsuccessful.  It is therefore very difficult to predict when companies will need to comply with new rules and precisely what information they will be required to disclose under new rules.

Despite that uncertainty, it appears very likely that the SEC will adopt final climate-related disclosure rules in the not-too-distant future and that those rules will include in some form most, if not all, of the big buckets of disclosure requirements reflected in the proposed rules.  Because of the significant effort and degree of organizational change that compliance with the rules likely will require, companies may not be able to wait until final rules are released to begin assessing the impacts of the proposed rules on their organizations.  And, if the SEC were to adopt final rules later this year in the proposed form, companies that are large accelerated filers with a calendar fiscal year would be required to include information for 2023, including Scope 1 and 2 emissions data, in their annual reports filed in early 2024, meaning that they would need to have the systems in place to track and record the relevant information by the end of this year.

Assessing the potential impact of the proposed rules on a company and preparing the company for eventually complying with the rules will require participation from many different parts of the organization, but we expect that, at many companies, the task of setting the company on a course to do those things will fall on the general counsel and other in-house counsel with responsibility for relevant substantive areas.  With that in mind, we have prepared the following guide for in-house counsel with respect to near-term actions their companies should be taking or should consider taking, depending on their circumstances.  Bracewell will expand on a number of the topics noted below in future alerts, webinars or other similar communications.

1.   Engage senior management, the board of directors and relevant board committees and begin assessing governance, oversight and management of climate-related risks.

In-house counsel likely will be hearing from their CEOs and board members, if they haven’t already, asking what the proposed rules mean for their company.  In any case, in-house counsel should ensure that top-level management and board members understand the potential challenges and changes their companies may face with the proposed rules and encourage the level of board and senior management oversight and engagement that is appropriate for their situation.  The proposed rules would require companies to provide detailed disclosures concerning their boards’ oversight of climate-related risks and management’s role in assessing and managing those risks. Although many companies already have robust board oversight of ESG matters and include related disclosures in their SEC filings, the proposed rules are far more granular in dictating the type of information that would need to be disclosed.

In that regard, in-house counsel may be asked what changes, if any, should be made to board or committee composition and structure in light of the proposed new disclosure requirements.  Among other matters, consideration should be given to whether the creation of a new ESG committee – or a purely climate-focused committee – is appropriate or whether responsibility reasonably can be shouldered by an existing committee, such as the audit committee.

2.   Establish organizational responsibility for assessing the implications of the proposed rules for your company.

As noted above, this is a huge task that will require input from a multidisciplinary team, including legal, accounting, operations and possibly other personnel.  Identifying the right team and setting clear responsibilities and timelines are critical near-term tasks.

3.   Understand the potential timeline for compliance with the proposed rules as it relates to your organization.

As noted above, there is considerable uncertainty regarding, among other matters, whether final rules will require compliance on the timelines contemplated in the proposed rules, which would have the compliance requirements phased in over several years based on a company’s status as a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company.  This fact sheet on the proposed rules published by the SEC provides helpful tables (on page 3) detailing the phase-in periods contemplated by the proposed rules for companies with a calendar fiscal year, assuming the proposed rules were adopted as final with an effective date in December 2022.

Despite the uncertainty, it is certainly possible that the SEC could adopt final rules later this year with compliance dates as contemplated by the proposed rules, and companies therefore would be ill-advised to assume that they will have a longer ramp-up period than they would under the proposed rules and the assumption of a December 2022 effective date.

4.   Understand the proposed rules and the disclosures they will require for your company based on its specific circumstances, including with regard to differences between what the company is disclosing now and what would be required by the proposed rules.

The proposed rules are highly prescriptive and are intended to produce consistent and comparable disclosures across the public-company spectrum.  With limited exceptions (e.g., that smaller reporting companies would be exempted from the requirement to disclose Scope 3 emissions), all public companies will need to assess required disclosure under all provisions of the rules.  That assessment, however, will need to be made in light of the company’s specific circumstances, and there will be categories of required disclosures that are very relevant to some industries or companies but of no or limited relevance to other industries or companies.  Additionally, many companies have been voluntarily disclosing information that is similar to some of the information that may be required to be provided under the proposes rules, but there may be gaps between or differences in required disclosures and a company’s current practices.

As companies begin to digest the proposed rules, it will make sense for them to drill down on the specific types of disclosures they would need to make if the proposed rules were adopted as proposed.  Questions that companies might ask themselves include the following:

  • Will we need to disclose Scope 3 emissions data based on materiality or having set targets or goals including Scope 3 emissions?
  • What, if anything, have we done with respect to the following topics such that disclosure regarding those topics would be required?
    • Adoption of a transition plan
    • Setting of climate-related goals or targets
    • Use of carbon offsets or renewable energy credits in setting goals or targets
    • Use of scenario analyses or other analytical tools in evaluating climate risk
    • Use of an internal carbon price
      • Note that, with respect to goals or targets, the proposed rules refer to a company’s having “set” such goals or targets and not to its having publicly disclosed them.  Similarly, with respect to all of these topics, it is not clear that the related disclosure would be triggered only by some level of formality or organizational scope in the adoption, setting or use of the applicable item.  Companies therefore should assess the relevance of these topics broadly, including informal use or discussion within the organization.
  • What information that we are not currently disclosing would the proposed rules require us to disclose?
  • For information that we are currently disclosing, would the proposed rules require that information to be established, assembled or disclosed differently, or disclosed more expansively or granularly, from how we are doing it now?  If so, how?
  • Which required disclosures might be particularly challenging for our company, such that they might merit special or prioritized focus?

5.   Begin to evaluate existing systems and resources related to climate-related information and identify changes that will need to be made.

Companies in some industries, such as energy or manufacturing, likely already have systems in place to collect much of the data called for by the proposed rules, and many public companies have been publishing voluntary disclosures in the form of ESG reports for years.  However, smaller companies in such industries may not currently have the resources necessary to devote to compliance with the new rules.  Likewise, companies in non-GHG intensive industries, such as financial services, previously may not have had the need, or a more limited need, for such systems.  And even those companies that are experienced in collecting and disclosing climate-related data and other information likely would, under the proposed rules, need to expand their systems to cover a much broader universe of information and ensure that controls and procedures meet standards for disclosures in SEC-filed documents and are appropriate for enhanced scrutiny and potential liability that will come with including such disclosures in SEC-filed documents.  Companies may need to invest significantly in new personnel with appropriate expertise and in new technology, and they will need to expand their disclosure controls and procedures and internal control over financial reporting to cover new sets of information that are wide-ranging, voluminous and highly detailed.  Accordingly, public companies should begin to assess their existing capabilities and identify the changes they would need to make to comply with proposed rules to ensure that the changes can be effected in time to comply with new rules.

Additionally, the climate-related risk disclosures contemplated by the proposed rules may require that companies devote significant resources to expanding the process by which they identify and assess climate-related risk.  Further, the need for companies to evaluate climate-related risks to upstream and downstream – value chain – activities, and potentially to disclose Scope 3 emissions associated with those activities, may pose significant challenges and likely will require many companies to develop new processes to address disclosure requirements that relate to matters that are largely outside of the company’s control and access.  These are areas that companies may want to focus on in the near term.

6.   Evaluate needs and strategy for retaining third parties to assist with disclosures, including for attestation of GHG emissions data.

As noted above, for large accelerated filers and accelerated filers, the proposed rules would require attestation regarding Scope 1 and Scope 2 GHG emissions data by an independent third party meeting certain minimum qualifications, which may be a public accounting firm if it meets the minimum qualifications but need not be an accounting firm.  The market for providing these attestation services is evolving and will continue to evolve as accounting firms and others develop their ability to provide these services.  Some observers have raised concerns that the supply of emission-attestation services may not initially meet the demand for such services that the proposed rules would create.  Companies may wish to begin thinking about their options for third-parties to handle the attestation, particularly large accelerated filers who could be subject to the attestation requirements as soon as in their 2024 annual reports filed in early 2025. Additionally, it is important for companies to have conversations around attestation ahead of their information gathering efforts to ensure that the disclosure information being developed and gathered will be sufficient for attestors to provide the required assurance.

In addition to attestation services, companies should consider their potential need for and access to other third-party advisors with the necessary expertise and experience, including attorneys, accountants/auditors and firms providing consulting and other services to assist companies with climate-related disclosures.

7.   Consider whether the disclosures contemplated by the proposed rules warrant any changes to your current, planned or contemplated climate-related activities, such as setting or disclosing of climate-related goals or targets.

As noted above, the proposed rules contemplate detailed disclosures regarding several matters that may or may not be relevant to a particular company depending on things that the company may or may not have done in advance of the initial compliance date for the proposed rules.  These include whether a company has:

  • adopted a climate transition plan,
  • set climate-related goals or targets,
  • included Scope 3 emissions in its goals or targets,
  • used carbon offsets or renewable energy credits in setting its goals or targets,
  • used scenario analyses or other analytical tools in assessing climate-related risk, or
  • used an internal carbon price.

Companies may wish to reassess their existing, planned or contemplated activities in these areas in view of the proposed rules.  It may be the case that a company would want to modify its activities in one or more of these areas when viewed through the lens of what the company’s disclosures regarding such activities would look like under the proposed rules.  For example, if your company is planning to set or announce new GHG emissions goals, should the company modify the goals as they relate to Scope 3 emissions or otherwise before doing so, or would it be preferable for the company to delay any such setting or announcement of goals until there is clarity on the content of final rules?

8.   Determine whether to submit comments on the proposed rules.

The proposed rule release includes over 200 requests for comment.  Comments are due by the later of 30 days after the date the proposing release is published in the Federal Register (which had not happened as of the date of this update) or May 20, 2022.  (As noted above, it is possible that the comment period could be extended beyond that date, but, unless and until the SEC actually does that, parties desiring to submit comments should proceed with the expectation that they will need to submit them by the applicable current deadline.)  Although the SEC will not agree with all comments received and may adopt final rules despite strong and widely-held opposing views reflected in the comments, the SEC and its staff will consider the comments received in adopting final rules and likely will make at least some changes to the proposed rules based on comments.  If your company would like to have its voice heard on the proposed rules, you may consider doing so by submitting comments directly or through an industry association or similar group.

9.   Monitor developments.

As noted above, we are in the early stages of the process through which the proposed rules could, in their current form or with changes, become final rules with which public companies actually would need to comply.  In-house lawyers should continue to monitor developments and advise others in their organizations of such developments as appropriate so that preparations for compliance with new climate-related disclosure rules can be adjusted as necessary.

10. Don’t forget that climate-related disclosures may be required under existing SEC rules and interpretations.

With the anticipation of a massive new disclosure regime for climate-related matters and preparation for compliance with that regime, it might be easy to overlook that fact the existing SEC rules and interpretations may require climate-related disclosures in SEC filings, and the SEC staff may issue comments on climate-related disclosures, or the absence thereof, in a company’s SEC filings, as they did for a number companies in the fall of 2021 with respect to the companies’ 2020 annual reports on Form 10-K.  Pending the adoption and implementation of final new rules, companies should continue to assess their disclosures in view of the SEC’s 2010 guidance on climate-related disclosures.

_______________________________________

1. Scope 1 emissions are direct GHG emissions from operations that are owned or controlled by a company.  Scope 2 emissions are indirect GHG emissions from the generation of purchased or acquired energy that is consumed by a company’s operations.  Scope 3 emissions are all indirect GHG emissions not otherwise included in a company’s Scope 2 emissions, which occur in the upstream and downstream activities of a company’s value chain.

© 2022 Bracewell LLP
For more about SEC disclosures, please visit the NLR Financial, Securities & Banking section.

Biden Administration Takes Aim at Advancing Gender Equity and Equality – Complementing Several Renewable Energy Private Sector Initiatives

On International Women’s Day, US President Joe Biden signed an Executive Order establishing the White House Gender Policy Council. The council, which was formerly called the White House Council on Women and Girls under the Obama administration, seeks to advance the equality of opportunity while simultaneously combating systematic biases and discrimination against women. The council plans to do this by coordinating federal government efforts to increase economic support, promote gender equity in leadership, prevent all forms of gender-based violence and bolster initiatives to empower women, both domestically and internationally. Although the election of Kamala Harris as the first female vice president in American history disrupted gender norms, the revival of this council serves as a salient reminder that there is still much to do to combat systemic biases and advance gender equality.

The federal government is not alone in its endeavor to combating gender inequity. Renewable energy has proven to be an industry where there is significant potential to break institutional biases. The renewable energy workforce, for example, comprises 32% women, whereas the larger energy sector workforce only employs 22% women. Although this is a notable start, these numbers illustrate that there is still progress to be made in achieving gender equality across industries and that these goals should be prioritized moving forward.

The renewable energy industry has several initiatives prioritizing gender equality that should continue to be lauded and supported. One such program is the Women of Renewable Industries and Sustainable Energy (WRISE) program, which supports the educational, professional development and advancement of women in the renewable energy sector with the aspiration of combating systemic inequities. The Women in Renewable Energy (WIRE) Network is a network of women working in renewable energy and combating existing structural gender inequities that could be exacerbated by the consequences of climate change. The Clean Energy Council’s Women in Renewables initiative serves as a platform to champion women working in renewable energy as they advance to become leaders of industry. Other notable programs and initiatives include:

  • Powered by Women, which consults with renewable energy companies on how they can sustainably build growth and close gender gaps at their respective organizations.
  • The Clean Energy Trust, a nonprofit supporting female or minority-owned startups aspiring to innovate in the realm of clean energy and sustainability.
  • The American Solar Energy Society, which is recognizing women who have contributed extraordinary developments to the technological developments or wide-spread advancement of solar energy.
  • The Department of Energy, which has sought to recruit more women into the clean energy field and recognize accomplished women for their contributions and leadership through the US Clean Energy Education & Empowerment (C3E) Initiative.
  • The Solar Energy Industries Association, which has developed the Diversity Best Practices Guide for the Solar Industry, aims to build a diverse workforce by providing guidance to companies as they navigate diversity and inclusion efforts.

The establishment of the Gender Policy Council displays a commitment by the United States to ensure that gender equality efforts are at the forefront of decision-making domestically and abroad, across multiple industries. In addition to naming two co-chairs, the council will comprise leaders from several agencies, including the secretary of energy, secretary of transportation, administrator of the Environmental Protection Agency and the chair of the Equal Employment Opportunity Commission. The array of individuals selected for the council will directly impact the renewable energy industry, as many of these offices are working in tandem to promote clean energy initiatives.

These efforts across industries and governments illustrate the promise and impact that the renewable energy sector has on empowering women. Only by advocating for the empowerment of all women, can we secure a safer, more renewable-energy-powered planet.

© 2020 McDermott Will & Emery

ARTICLE BY Carl J. Fleming and Elle Hayes of
McDermott Will & Emery
For more articles on the Biden administration, visit the NLR Environmental, Energy & Resources section.

FERC Redefines QF Eligibility Requirements

On September 1, 2020, the Federal Energy Regulatory Commission (“FERC” or “Commission”) issued an order breaking with decades of precedent regarding how it will determine whether a renewable resource is eligible for certification as a qualifying small power production facility (“QF”) pursuant to the Public Utility Regulatory Policies Act of 1978, as amended (“PURPA”).[1]  The result of the Commission’s order is that renewable resources will no longer have the ability to qualify for QF status by voluntarily limiting their output to comply with the 80 MW cap on small power production facilities.  Commissioner Richard Glick dissented and we anticipate that parties to the proceeding will seek rehearing and possibly appeal the order to federal court.  Bracewell will keep you updated on significant PURPA developments.

PURPA and the Commission’s implementing regulations limit a small power production QF’s capacity to a “power production capacity” of 80 MW.[2]  When evaluating whether a facility complied with this requirement, the Commission focused on the “maximum net output of the facility that can be safely and reliably achieved under the most favorable operating conditions likely to occur over a period of several years.”[3]  In practice, the Commission’s focus on the maximum net output of the facility—rather than the installed capacity of the equipment at the site—has meant that developers have been able to qualify for QF status by voluntarily installing control systems or taking other steps to limit the sustainable net output of the generation facility in any given hour to 80 MW or less, even if the installed generation capacity of the facility exceeded the 80 MW cap.

In the proceeding resulting in the September 1 Order, the Commission considered whether a combined solar and storage facility owned by Broadview Solar, LLC complied with the 80 MW cap.  The facility at issue consisted of a 160 MW solar array and a 50 MW battery storage system that would connect to 82.5 MW DC-to-AC invertors.  Because any energy produced by the solar array and battery storage system would need to be converted from DC power to AC power prior to the injection in the grid, the maximum achievable output from the facility in a given hour was 82.5 MW.  Thus, even though the installed capacity of the solar array and storage system exceeded the 80 MW cap, Broadview explained that the net output of the facility, taking into account losses and station load, could never exceed 80 MW.[4]

The Commission rejected Broadview’s arguments, however, and found that Broadview’s facility cannot meet the requirements for QF status.  The Commission acknowledged that previous orders had allowed “facilities with greater power production capacities to be certified as QFs when the net output was no more than 80 MW.”[5] The Commission found, however, that this interpretation was inconsistent with the plain language of PURPA limiting the “power production capacity” of QFs to 80 MW.  While the Commission recognized that the inverters were only capable of converting 80 MW into AC power, the Commission observed that this was merely a “conversion limit” and that the solar array alone had the capability to produce 160 MW of DC power.  According to the Commission, “[u]tilizing inverters to limit the output of an otherwise above-80 MW power production facility to 80 MW is . . . inconsistent with the type of facility that Congress specified can qualify as a small power production facility (i.e., a facility sized 80 MW or less).”[6]  For that reason, the Commission found that Broadview’s facility did not meet the requirements to qualify as a QF.

Recognizing the potential impact of its abrupt change in policy, the Commission explained that its finding would only be applied prospectively.[7]  As a result, the Commission’s order will not affect “QFs that have self-certified [through the submission of FERC Form 556] or have been granted Commission certification prior to the date of” the Commission’s order, even if the self-certification filed by the facility “included adjustments for inverters or other output-limiting devices to calculate its maximum net power production capacity as 80 MW or less.”[8]

The Commission’s order represents a marked departure from Commission precedent that  effectively eliminates the ability of renewable resources to meet the QF certification requirements by limiting the output of their facility so that it does not exceed 80 MW.[9]  Although the Commission indicated that it would only apply this determination prospectively, the Commission’s decision could have significant implications for projects that are in the final stage of development, but have not yet filed a notice of self-certification to FERC.[10]  The Commission emphasized, for example, that the owner of a facility with a legally enforceable obligation could not benefit from “grandfathered” status for the facility in the absence of a self-certification Form 556 submittal or FERC order granting certification before September 1, 2020.[11]  Also, the Commission’s order does not address whether the Commission would be willing to revisit the QF status of facilities that submit a notice of re-certification in order to report a change in the facts reported in its initial certification, including upgrading, modernizing or retrofitting existing facilities.[12]  The Commission did, however, clarify that load and line losses could continue to be factored in when measuring a facility’s 80 MW maximum net power production.

The Commission expressly declined to address how the capacity of an energy storage system should be taken into account for QF purposes – an aspect of the proceeding that many were following.[13]  In a number of recent proceedings, companies developing renewable resources combined with battery storage have taken the position that the capacity of a battery storage system should not be included when calculating the net capacity of the facility on the basis that the storage does not represent an additional source of independent power generation and merely allows the facility to shift the time of production; in those cases, however, the QF certification application was withdrawn before FERC made a substantive determination on the issue.[14]  Broadview took a similar position in this proceeding, arguing that aggregating the combined capacity of the solar array with the energy storage system would artificially inflate the aggregate capacity of the facility components.  The Commission found that it did not have to address that issue in this case because the 160 MW solar array on its own without considering the energy storage facilities was already double the 80 MW cap.[15]

 

[1] Broadview Solar, LLC, 172 FERC ¶ 61,194 (2020).

[2] 16 U.S.C. §§ 796(17), 824a-3; 18 C.F.R. § 292.204.

[3] Occidental Geothermal, Inc., 17 FERC ¶ 61,231, at 61,445 (1991).

[4] Id. at P 3.

[5] Id. at P 21.

[6] Id. at P 25.

[7] See id. at P 27.

[8] Id.

[9] See id. at P 27.

[10] Id.

[11] Id.

[12] See id.

[13] Id. at P 21 n. 57.

[14] See, e.g., NorthWestern Corp., 168 FERC ¶ 61,049 (2019).

[15] Broadview, 172 FERC ¶ 61,194, at P 21 n. 57.

© 2020 Bracewell LLP
For more articles on the environment, visit the National Law Review Environmental, Energy & Resources section.

DOER Finalizes SMART Program Emergency Regulations

The Department of Energy Resources (DOER) has finished the required Solar Massachusetts Renewable Target (SMART) Program 400MW review and emergency rulemaking and published its final regulations. Several revisions and adjustments have been made to the final regulations, including an extension to the COVID-19 extension for new applications received through December 31, 2020.

Revisions have been made to previously published land-use exceptions. Projects that meet the below criteria will now be assessed under the former land-use regulations:

  • Have applied for the Interconnection Service Agreement (ISA) 135 business days prior to April 15, 2020, or have obtained a fully executed ISA by October 15, 2020; and
  • Have obtained a sufficient interest in real estate or other contractual rights to construct the Solar Tariff Generation Unit at the location specified in the ISA as of April 15, 2020.

Additionally, the DOER distinguished eligible land use between projects qualifying for capacity as part of the original 1600MW versus projects qualifying under the new 1600MW. Projects qualifying under the original 1600MW will be eligible for the SMART Program even if located on land designated as Critical Natural Landscape, while projects qualifying under the new 1600MW will be ineligible if the project is sited in a Priority Habitat, Core Habitat, or Critical Natural Landscape.

The final regulations also allow for single-axis trackers to be eligible for the Tracker Adder, and behind-the-meter systems to receive Alternative On-Bill Credits.

The DOER also made modifications to the Statement of Qualification Reservation Period Guideline. In addition to continuing the COVID-19 extension for new applications, the DOER has done the following:

  • Eliminated the requirement that projects obtaining an indefinite extension, pending the authorization to interconnect, must submit a claim within 10 business days of receiving the authorization to interconnect;
  • Granted eligible Public Entity Off-taker Adder Solar Tariff Generation Units an initial Reservation Period of 18 months;
  • Clarified that projects qualified as Community Shared Solar that do not submit a claim with the CSS Adder will have their base compensation rate decreased to the value in the lowest available Capacity Block, but will not be at risk of losing their Statement of Qualification outright: and
  • Established a process by which DOER will queue project applications if there is a rush of applications submitted following the issuance of ISAs by a Distribution Company upon the completion of an ASO study.

Several other Guidelines related to the SMART Program are still being revised, and the DOER is expected to release these updates in the coming weeks. Publication of the regulations is just the beginning phase for resuming the SMART Program. Changes to the regulations that affect the tariff will now need to be implemented into each Electric Distribution Companies’ tariffs and undergo administrative review of the Department of Public Utilities.

© 2020 SHERIN AND LODGEN LLP

For more on solar renewable energy, see the National Law Review Environmental, Energy & Resources law section.