Yesterday, President Trump signed into law the Export Control Transparency Act. While this new law includes a confidentiality provision, organizations submitting export license applications to the Commerce Department’s Bureau of Industry and Security (BIS) should, in some cases, be concerned about the implications.

For certain types of license requests, the name of the applicant, end user, type of product/technology, value, and other details will be reported to Congress. In many cases, this information is quite sensitive. For example, suppliers may not be aware that their products are being exported to restricted end users, and may object to this (even if fully lawful), jeopardizing supply chains. Banks and other partners may increase scrutiny. Valuations on export license applications can be misleading and may give rise to hard questions. Of course, outside attention to business with restricted parties is typically not desirable, and companies probably won’t be able to provide the proper context to explain the information being reported.

Therefore, a major looming question for organizations within this law’s scope is the likelihood that members of Congress or their staff may publicly disclose the information that is reported to them or otherwise use it in unintended ways. Many organizations will not be comfortable with this risk and will look for alternative strategies. Some may reconsider opportunities to remove their exports from BIS’s licensing jurisdiction. As a result, this law may further discourage U.S. exports and add another incentive for offshoring, reducing U.S. sourcing, etc.

However, the narrow scope of the law is helpful. It only covers applications for export, transfer, etc. “to covered entities,” which must be both: 1) located in a U.S. arms-embargoed country (e.g., China), and 2) on the BIS Military End-User List or Entity List. With this in mind, only a tiny proportion of applications to BIS must be reported to Congress under this law.

If you have any questions about these developments, please contact a member of our Sanctions + Trade Controls team.

Despite the avalanche of lawsuits and enforcement actions related to tracking technology, companies can take at least some solace in a recent decision curtailing Video Privacy Protection Act (VPPA) lawsuits. On July 28, the U.S. Court of Appeals for the Second Circuit denied a petition for en banc review of its May 1, 2025, decision affirming an Eastern District of New York court’s order in Solomon v. Flipps Media, Inc. d/b/a Fite, d/b/a Fite TV,[1] dismissing a putative class action alleging violations of the VPPA.

This victory, however, should be read in light of the recent significant increase in California Invasion of Privacy Act claims after efforts to amend the law stalled in the California legislature and after a jury found Meta liable for potentially substantial damages for violating that law. Further, regulators have focused on tracking technologies, including recent enforcement actions by the California Privacy Protection Agency costing entities millions of dollars. These recent developments are a reminder that the decision to implement tracking technologies is no longer just a marketing decision. It is a decision that has significant legal impact that can cost companies millions of dollars.

Nonetheless, the Second Circuit’s recent VPPA decision is significant and beneficial for defendants. Below, we provide an overview of the decision and its context.

Background

In Flipps Media, plaintiff Detrina Solomon, a subscriber to defendant Flipps Media’s streaming service, sued the company claiming it violated the VPPA by deploying the Meta Pixel on its website, and allowing it to share her video viewing information with Meta without her consent. The video viewing information that allegedly was shared consisted of the URL containing the title to a video contained on webpages she allegedly visited along with her Facebook ID number (FID), which identified her Facebook profile. Flipps Media filed a motion to dismiss in response to the lawsuit on the basis that the complaint failed to plausibly allege Flipps Media disclosed “personally identifiable information” under the VPPA.[2]Flipps Media argued that it did not share “personally identifiable information”[3] because the information transmitted by the Pixel consisted of lines of code containing a sequence of characters, letters, and numbers which were not interpretable by an ordinary person.

On September 30, 2023, the district court granted the motion and dismissed the complaint. In its ruling, the district court adopted the “ordinary person” standard for determining “personally identifiable information” under the VPPA. Under the “ordinary person” standard, which had been previously adopted by the Third Circuit in In re Nickelodeon Consumer Priv. Litig.[4] and the Ninth Circuit in Eichenberger v. ESPN, Inc.,[5] only information “that would readily permit an ordinary person to identify a specific individual’s video-watching behavior” qualifies as “personally identifiable information” under the VPPA. [6] This “ordinary person” standard, has not been followed by the First Circuit. In Yershov v. Gannett Satellite Info. Network, Inc.,[7] the First Circuit adopted a “reasonable foreseeability” standard, which simply requires proof that the information being shared was reasonably and foreseeably likely to reveal the identity of an individual and the videos that individual viewed or requested.

In Flipps Media, the district court adopted the “ordinary person” standard, rather than the “reasonable foreseeability” standard and found the lines of code containing the URL and FID that were transmitted to Meta could not be interpreted by an ordinary person as disclosing the identity of the plaintiff and the videos she watched. Accordingly, the district court found the complaint could not plausibly allege the sharing of “personally identifiable information” and dismissed the complaint. The district court also denied the plaintiff’s motion seeking leave to amend.

Appeal to the Second Circuit

On October 27, 2023, plaintiff appealed the order, dismissing her complaint to the Second Circuit. In her appeal, the plaintiff’s primary argument was that the Second Circuit should adopt “a variation of Yershov’s reasonable foreseeability standard and hold that ‘personally identifiable information under the VPPA encompasses specific information about a consumer, disclosed by a video tape service provider to a particular recipient, that the provider knows the recipient can use to personally identify that consumer.'”[8] Alternatively, the plaintiff argued that the information transmitted by the Pixel met both the “reasonable foreseeability” and “ordinary person” standards for “personally identifiable information.”

On May 1, 2025, the Second Circuit issued its first opinion interpreting the definition of “personally identifiable information” under the VPPA, affirming the dismissal of the plaintiff’s complaint. In the opinion, the Second Circuit examined both the “reasonable foreseeability” and “ordinary person” standards, and concluded that the language, legislative history, and specific context of the VPPA dictate that the statute precludes knowingly disclosing information that would allow an ordinary person to identify a specific person’s video-watching behavior, not information “that only a technology sophisticated third-party” could use to identify specific customers.[9] In particular, the Second Circuit held that the VPPA’s focus is on what the disclosing party provides, not what the recipient can do with the disclosed information. Applying the “ordinary person” standard, the court found that lines of code displaying the video title, URL, and the plaintiff’s FID could not be read by an ordinary person to identify the specific videos on Flipps Media‘s website the plaintiff had watched. In reaching this conclusion, the Second Circuit focused on the characters, numbers, and letters interspersed within the words of the title and ruled it “implausible that an ordinary person would understand, with little or no extra effort … the video title.”[10] As for the FID, the court found that the FID “would be just one phrase embedded in many other lines of code” and therefore it was “not plausible” that an ordinary person would see the phrase, conclude it was a person’s FID, and use it to access the person’s Facebook profile.[11]

Request for En Banc Review

The plaintiff filed a petition for en banc review of the Second Circuit’s ruling. In the petition, the plaintiff challenged the court’s adoption of the “ordinary person” standard as being contrary to the text and purpose of the VPPA. The plaintiff argued that the “reasonable foreseeability” standard, which would focus on whether Meta, as opposed to an ordinary person, could interpret the information the Pixel transmitted, should be applied. The plaintiff further argued that the review of the court order was necessary because the decision had “effectively shut the door for Pixel-based VPPA claims.”

On July 28, 2025, the Second Circuit denied the plaintiff’s request for an en banc review. The plaintiff now has until October 26, 2025, to file a petition for certiorari with the U.S. Supreme Court.

Takeaways

The Flipps Media decision is the first circuit court ruling to apply the ordinary person standard to VPPA claims premised on information transmitted by the Meta Pixel. This commonsense approach is welcomed by digital streaming companies, the news media, and entities that offer video clips on their websites. Businesses now have the trio of cases, Nickelodeon, ESPN, and Flipps Media, to combat VPPA claims at the pre-answer motion to dismiss stage. While a petition to the Supreme Court may still occur, the sound reasoning of the Second, Third, and Ninth Circuits should prevail and put an end to VPPA claims premised on the transmission of information through the Meta Pixel.

Despite the Flipps Media decision, businesses that employ tracking technologies should understand the technologies being deployed and the various type of data being shared in order to reduce the risks of additional lawsuits being pursued under different theories.

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[1] Solomon v. Flipps Media, Inc. d/b/a Fite, d/b/a Fite TV, No. 2:22-cv-05508 (E.D.N.Y. 2022).

[2] The defendant also argued that the complaint did not plausibly allege that the plaintiff is a “consumer” of a “video tape service provider” as those terms are defined by the statute. The trial court rejected this argument and it was not substantively addressed on appeal.

[3] The VPPA does not specifically define “personally identifiable information” (PII). Instead, it states that PII under the statute “includes information which identifies a person as having requested or obtained specific video materials or services from a video tape service provider.” 18 U.S.C. § 2710(a)(3).

[4] In re Nickelodeon Consumer Priv. Litig., 827 F.3d 262, 267 (3d Cir. 2016).

[5] Eichenberger v. ESPN, Inc., 876 F.3d 979, 985 (9th Cir. 2017).

[6] See In re Nickelodeon Consumer Priv. Litig., 827 F.3d at 267; Eichenberger, 876 F.3d at 985.

[7] Yershov v. Gannett Satellite Info. Network, Inc., 820 F.3d 482, 486 (1st Cir. 2016).

[8] Solomon v. Flipps Media, Inc. d/b/a Fite, d/b/a Fite TV, 136 F.4th 41, 51 (2d Cir. 2025).

[9] Solomon, 136 F.4th at 52.

[10] Id. at 54.

[11] Id.

Troutman Pepper Locke’s Cannabis Practice helps clients throughout their business cycle enter or expand into the cannabis space. Our team combines the resources of attorneys in areas such as licensing and taxation, regulatory compliance, corporate and transactional, intellectual property, and real estate, among others, to provide comprehensive services.

Our Cannabis Practice provides advice on issues related to applicable federal and state law. Cannabis remains an illegal controlled substance under federal law.

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Cannabis Regulatory Updates

Bipartisan State AGs Urge Congress to Grant Access to Federally Regulated Banking and Financial Services to State-Regulated Cannabis Businesses

By Troutman Pepper Locke State Attorneys General Team, Jean Smith-Gonnell, and Cole White

In July 2025, a bipartisan coalition of 32 state and territorial attorneys general (AG) sent a letter to congressional leaders urging the passage of the Secure and Fair Enforcement Regulation (SAFER) Banking Act. Their letter emphasizes that the legislation — a long-stalled federal reform — would provide legal clarity and a safe harbor for banks and financial institutions to serve state-licensed cannabis businesses. Such clarity, they argue, is urgently needed to address public safety risks and to improve the states’ ability to regulate and tax the booming cannabis industry.

Read more

Our eMerge team is excited to share the following updates:

• Client Care Survey: Coming soon via email — keep an eye out!
• Case Study: Remote, targeted mobile device discovery.
• Awards and Recognition: Vote for eMerge Split!
• Thought Leadership: Microsoft 365 eDiscovery and Copilot updates and more.
• Events and Speaking Engagements: Discover the latest insights and updates on Microsoft 365.

Troutman Pepper Locke’s award-winning eDiscovery, data management, and AI subsidiary, eMerge, offers clients integrated technology and legal solutions to address complex data-driven problems in litigation, transactional and compliance matters, government investigations, and information governance initiatives.

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Client Care Survey

To ensure eMerge is delivering exceptional service to all its clients, both internally and externally, we will periodically request feedback through client satisfaction surveys. Please look out for these surveys via an automated external email from Alison Grounds with the subject line, “Troutman eMerge Client Satisfaction Survey – [Name of current matter].”

 

 

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Insurance Litigation Case Study: Mobile Device Discovery

eMerge was engaged to manage the discovery process in a complex insurance litigation matter where the client faced a fast-approaching discovery deadline involving multiple custodians’ mobile devices. The challenge was familiar: collect and prepare relevant mobile data for review and production, while minimizing custodial disruption and protecting unrelated, personal, and confidential client information.

Instead of conducting a complete forensic acquisition of each mobile device, eMerge deployed ModeOne’s mobile collection technology to efficiently target only the potentially relevant data for collection. eMerge’s ModeOne-powered collections proceed as follows:

• First, eMerge works with the custodian or their IT designee to install the ModeOne application directly on the target Android device or on a computer to which a custodian can connect their iOS device.
• Second, eMerge’s collection analysts remotely access the device to identify the specific categories of data subject to collection, such as photos, videos, messages, phone logs, and contacts.
• Third, ModeOne uploads the data to a secure cloud environment.
• Finally, eMerge filters the data as needed and exports the results in a format amenable to efficient review, such as Relativity Short Message Format (RSMF).

Utilizing ModeOne substantially accelerates collection timelines, reduces the risk of overcollection, and safeguards personal and confidential information. On the complex insurance matter, we completed a process that typically takes days in hours, yielding significant downstream review and production savings. eMerge has a variety of collection tools and can identify a defensible approach suitable to each matter.

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Awards and Recognition

Vote for eMerge Split! 

We are pleased to share that eMerge Split!, developed by eMerge’s Custom Solutions team, has been nominated for the 2025 Relativity Innovation Awards for Best Innovation: Organize. The Relativity Innovation Awards’ Organize award celebrates innovations that transform the way we store, structure, collect, process, and organize critical data. Click here to learn more and vote for eMerge Split!

Troutman Pepper Locke Announces 2025 Legal 500 US Rankings

eMerge has been ranked by Legal 500 in the Dispute Resolution: eDiscovery category. This prestigious recognition underscores our unwavering commitment to delivering exceptional service and innovative solutions to our clients. We are delighted to highlight the individual accolades received by eMerge Managing Partner Alison Grounds, Principal Jim Calvert, and Principal Jason Lichter, who were mentioned in the 2025 edition. Alison was recognized as a “leading lawyer.” Click here to read more.

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Thought Leadership

Cleared for Takeoff? Copilot Legal and Technical Preflight Checklist
Millions of companies use the Microsoft 365 suite of tools every day to create, communicate, and collaborate, but far fewer have adequately grappled with the legal risks introduced by Copilot, the powerful generative AI assistant embedded in those same applications. While Copilot can enhance employee productivity, creativity, and connectivity, it may do so at the expense of privacy, security, and compliance without adequate planning and oversight. Click here to read the full article authored by eMerge Principal Jason Lichter.

Microsoft 365 eDiscovery Updates

Microsoft released its new unified eDiscovery experience (Purview eDiscovery) within the Purview portal. Microsoft describes Purview eDiscovery as “a modernized user interface for key eDiscovery workflows, with simplified creation for cases, searches, and holds.” Click here to read the full update.

Navigating the Maze: eDiscovery Essentials for Employers

In this episode of Hiring to Firing, Partners Tracey Diamond and Emily Schifter explore eDiscovery processes and procedures with eMerge Managing Partner Alison Grounds. Learn about the importance of eDiscovery in litigation and the complexities of managing electronic data. Click here to listen to the podcast episode.

Harnessing the Power of eDiscovery: The Revolution of AI and Technology in Litigation and Investigations

In this episode of The Consumer Finance Podcast, Partner Chris Willis is joined by Partners Joseph DeFazio and Jason Manning, along with eMerge Managing Partner Alison Grounds, to discuss the evolving capabilities and advantages of eDiscovery. This episode highlights the significance of efficient processes in streamlining document review to enhance legal strategies, including setting clear policies for electronically stored information (ESI) and analyzing vast volumes of digital data with accuracy. Click here to listen to the podcast episode.

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Events and Speaking Engagements

Webinar – ESI Protocols

Our team discussed the benefits and risks of drafting protocols for the exchange and handling of ESI in litigation. The presentation included strategic tips on drafting, revising, and negotiating protocols, highlighting essential elements and common pitfalls to help minimize eDiscovery disputes. Click here to view the recording.

Webinar – Microsoft 365 eDiscovery Updates

eMerge hosted a webinar exploring the latest changes to Microsoft 365 Purview’s eDiscovery solution. View the webinar recording.

Webinar – Transcript Tactics: Best Practices for Deposition Review in the Age of AI
eMerge Director of Legal Technology Antonio Avant presented on AI-enhanced deposition preparation during a webinar hosted by the Association of Certified E-Discovery Specialists. Antonio and the other panel members discussed how to efficiently and accurately analyze deposition transcripts.

Relativity’s AI Bootcamp: Powering the Future of Legal

eMerge Principal Jason Lichter gave the welcome and closing remarks as the anchor of Relativity’s AI Bootcamp: Powering the Future of Legal. The program brought together practitioners and thought leaders at the forefront of technological innovation to discuss the evaluation and adoption of cutting-edge AI technologies.

Troutman Pepper Locke Partners Albert Bates, Zachary Torres-Fowler, and David E. Harrell published an article titled “Contractor’s Claims, Remedies and Reliefs” in Global Arbitration Review. 

Introduction

Construction and engineering disputes continue to make up one of the largest industry sectors for international arbitration institutions around the world. Given the technical complexity and lengthy duration of many construction projects, disputes are almost inevitable. Contractors must understand their rights and how best to protect their interests during an ongoing project. In the often rough and tumble world of international construction projects, a contractor’s failure to carefully enforce its rights may lead to hardship that could have otherwise been avoided.

Click here to read the full article in Global Arbitration Review.

Synopsis

The Internal Revenue Service (IRS) released a Generic Legal Advice Memorandum, GLAM 2020-004 (the IRS Memo) dated May 18, 2020 addressing the timing of income and payroll tax withholding on three types of employee equity awards: nonqualified stock options (Options), stock-settled stock appreciation rights (SARs), and stock-settled restricted stock units (RSUs). 

For publicly traded companies, the IRS Memo clarifies that Options and SARs are taxable when exercised, even though shares may not be delivered to the employee’s brokerage account for up to two days after exercise. This conclusion should be unsurprising to most employers. 

More interestingly, the IRS Memo states that RSUs are treated as taxable when the employer “initiates payment” of the RSUs to employees. This “initiates payment” standard for RSUs appears to be a new concept and could prove helpful to some employers. This article explores some planning opportunities for employers related to this standard.

The Basics of Options, SARs, and RSUs

Options, SARS, and RSUs have the following basic features:

• An Option is a contractual right, granted by an employer to an employee, for the employee to purchase a fixed number of employer shares at a fixed price (the exercise price) during a fixed period of time (the option term). The exercise price is typically the fair market value of the shares on the grant date, and the option term is usually 10 years (or less due to termination of employment). An employee’s right to exercise is usually conditioned on meeting vesting requirements specified in the award agreement. To exercise the Option, the employee normally must provide a written exercise notice plus payment in full of the exercise price. The employee must also provide funds to satisfy all tax withholding obligations (discussed further below).[1] 

• SARs are economically similar to Options, but do not require the employee to pay an exercise price. Instead, SARs entitle the employee to receive upon exercise the difference between the value of the underlying shares on the date of exercise and the SAR “base price,” which (like the Option exercise price) is typically the fair market value of the shares on the grant date. For a stock-settled SAR, this spread in value upon exercise is paid by delivery of a number of shares equal in value to that spread. The IRS Memo addresses only stock-settled SARs.

• An RSU is a contractual right of an employee to receive a specified number of the employer’s shares at a later date, after satisfying any applicable vesting requirements. The vesting requirements could include continued employment through scheduled vesting dates (sometimes referred to as “time-vesting” RSUs) and/or achievement of performance goals (sometimes referred to as “performance-vesting” RSUs, or PSUs). The employee pays no exercise price. The date the shares are to be paid is often the date the vesting requirements are met, but can also be a later specified date. The design of RSUs needs to consider compliance with the deferred compensation rules under Internal Revenue Code Section 409A and the “special timing rule” for FICA taxes (i.e., Social Security taxes up to the Social Security wage base plus Medicare taxes), especially if the payment date can occur in a later year after the vesting date.[2] 

When a taxable event for an Option, SAR, or RSU occurs for an employee, the employer must determine the amount of taxable income that will be included in the employee’s W-2 taxable wages for the year. The employer also must withhold all applicable federal, state, and local income taxes and applicable FICA taxes.[3] The IRS Memo addresses how and when these taxable wages and withholdings are determined.

Timing and Amount of Taxation Per the IRS Memo

For public companies, there is usually a brief delay between when Options and SARs are exercised and when shares are actually delivered to the employee (usually into a brokerage account with a third-party administrator for the employer’s equity compensation plan). A similar delay can occur between the date that an employer starts the process to issue shares in payment of an RSU and the date that the shares are actually delivered to the employee’s brokerage account.

The IRS Memo addresses when the taxable event is considered to have occurred for these transactions. The date of the taxable event is important for at least two reasons:

• determining the fair market value of the shares to determine the amount of taxable income, and

• determining when tax withholding deposits are due.

The IRS Memo includes examples for each type of award. 

For Options and SARs, taxation occurs upon exercise. In the examples in the IRS Memo, if an Option with an exercise price of $10 is exercised on Day 1 when the stock has a fair market value[4] of $25, the amount of taxable income is $15 (i.e., $25 – $10). This calculation applies even if the shares are not actually delivered to the employee until Day 3, and even though on Day 3 the stock is worth $24. In accordance with the IRS Memo, once the exercise has occurred, the employee is considered to have beneficial ownership of the shares to be delivered, because the employee stands to participate in any increase or decrease in the value of those shares after exercise.

As noted above, there is no exercise date for RSUs. According to the IRS Memo, the tax date for RSUs is the date that the employer “initiates payment.” As in the examples for Options and SARs, if the shares are worth $25 on Day 1 when the employer initiates payment of vested RSUs, that $25 value will be the price used to determine the amount of income taxes and withholdings for the RSUs, even though the shares are not actually delivered to the employee until Day 3 when the shares are worth $24. Similar to the analysis for Options and SARs, the IRS concludes that the employee has beneficial ownership in the shares once payment has been initiated by the employer.

The IRS Memo does not expressly define what “initiates payment” means, but indicates that a public company initiates payment when it instructs its transfer agent to transfer shares to the employee’s brokerage account. 

Many employers will initiate payment for an RSU on the scheduled vesting date. This approach is especially common for typical time-vesting RSUs. In those cases, the vesting date fair market value of the shares will determine the amount of taxable income and withholdings. This result likely represents no change in practice for many employers.

But the design of some RSUs will require the recognition of income on dates other than the vesting date.[5] For example, many RSUs provide for payment within a specified period (e.g., 30 days) following the applicable vesting date. PSUs often provide for payment during a period (e.g., 2 ½ months) following the end of the applicable performance period and after performance results have been certified. In these cases, employers will have flexibility in determining when to initiate payment within the stated period, and the employer’s decision as to the date that the payment is initiated will determine the date of income inclusion according to the IRS Memo.

Unlike Options and SARs, RSUs can also have deferred payment dates, subject to compliance with Section 409A. If a deferred RSU is payable on a future fixed date or permissible payment event (such as termination of employment), the taxable amount and withholdings should be based on when the employer initiates payment following that permissible payment date or event.[6]

Interplay with One-Day Rule

The IRS Memo reaffirms that the deposit of employment taxes (i.e., both required income tax withholdings and FICA taxes) must occur within one business day after the relevant tax event for Options, SARs, and RSUs if the employer has accumulated $100,000 or more in employment taxes during a monthly or semi-monthly deposit period (the One-Day Rule). The IRS Memo confirms that the clock for the One-Day Rule starts on the day of exercise for Options and SARs and the day the employer initiates payment for RSUs, so that employment tax deposits are technically due the following business day.

The One-Day Rule can present a challenge for public companies when (i) shares from the award are sold by the employee on the date of Option/SAR exercise or RSU payment to fund required tax withholding, but (ii) the proceeds of the same-day sales are not deposited until two days later, consistent with “T+2” settlement requirements under current Securities and Exchange Commission (SEC) rules. The IRS previously issued a 2003 Field Directive in which it directs agents to not assert penalties on employers that fail to satisfy the One-Day Rule in connection with Option exercises if the employer deposits employment taxes within one day after settlement of the shares, assuming settlement occurs within three days after exercise (consistent with the SEC’s “T+3” settlement requirement that applied at that time). 

The omission of SARs and RSUs from the 2003 Field Directive was not especially significant or surprising at that time, as those award types were not common then. Since then, however, the popularity of RSUs has increased substantially and the absence of relief for RSUs from the One-Day Rule has become a practical problem for some employers. 

Thankfully, immediately after publication of the IRS Memo, the IRS revised its Internal Revenue Manual field agent guidance to provide relief from the One-Day Rule for SAR exercises and RSU payments, as well as Option exercises. The revision states that agents may waive otherwise applicable late deposit penalties if employment taxes are deposited within one business day after the “T+2” settlement date for SARs and RSUs, as well as Options.[7] 

Planning Opportunities for Employers

The new “initiates payment” standard for the timing of taxation for RSUs may present employers with planning opportunities. Some of the possible planning opportunities include:

• having a single payment date for administration of tax reporting and withholding for RSUs and PSUs that vest on multiple prior days during a year,

• timing the payment date to be during an open trading window (e.g., three days after public release of quarterly or annual financial statements), and

• timing the payment date in coordination with dividend record dates (e.g., so that the shares delivered in settlement will qualify to receive the dividend).

For example, assume an employer has time-vesting RSUs that vest on February 12, 14, and 15 during 2021. Assume there is also a PSU award with a 2018-2020 performance period that the compensation committee, at its meeting in February 2021, determines was earned at target. Assume the employer plans to file it’s 10-K at the end of February, with an open trading window under their insider trading policy starting on March 4. If the award agreements include language permitting the employer to pick a payment date within a specified administrative period (e.g., on a day no later than March 15, 2021), the employer could select March 4 as the payment date for all of these awards and initiate payment on that date. This single payment date for the various awards could provide several potential benefits, such as:

• simpler administration for tax reporting and withholding (e.g., by having a single stock price to value all of the awards for tax purposes);

• if share withholding is used to cover taxes for Section 16 officers, simpler Form 4 filing requirements (with a single Form 4 reporting those share withholding transactions for each Section 16 officer); and

• if tax withholding is to be covered through employee-directed broker sales of shares subject to the awards, simpler compliance with insider trading policy requirements (i.e., by having the sale transactions executed during an open window).

Public companies looking to conserve cash during the economic crisis created by COVID-19 may also want to consider greater use of broker sales to cover tax withholding obligations related to stock-settled SAR exercises and RSU payments. Previously, this approach was not possible without exposing the employer to late deposit penalties or without the employer using its cash to advance the proceeds expected from employee-directed broker sales. The recent IRS clarification about application of the One-Day Rule to these transactions (described above) will facilitate timely tax deposit using this approach.

Conclusion

While the IRS Memo likely does not change the tax reporting and withholding practices as to Option and SAR exercises for most public company employers, it does present some planning opportunities regarding the settlement of vested RSUs and PSUs. Employers may wish to review their RSU and PSU awards agreements and related tax administrative practices and consider whether any changes are appropriate or desired.

 

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[1] A “statutory option” or “incentive stock option” (an ISO) is a special kind of stock option that meets certain technical requirements under the Internal Revenue Code, and provides employees with special tax benefits. The Options discussed in the IRS Memo are not ISOs, but are “non-qualified stock options” that are generally taxable upon exercise.

[2] Options and SARs are usually designed to be exempt from the requirements of Section 409A. When RSUs vest in one year but are paid in a later year, FICA taxes are usually due in the year of vesting, even though income taxes are not due until the year of payment. This is sometimes referred to as the FICA tax “special timing rule.”

[3] See footnote 2 regarding the FICA tax special timing rule that sometimes applies to RSUs, depending on the design. The guidance in the IRS Memo does not change the special timing rule. The examples in the IRS Memo related to RSUs were designed so that income and FICA taxes became due at the same time.

[4] Public company employers have some flexibility in how the fair market value of the shares are determined at the time of exercise for purposes of calculating taxable income. Employers may use any reasonable method for determining fair market value for income recognition purposes. Depending on the facts and circumstances, these methods may include closing price on the day of the taxable event, closing price for the prior day, an average of high and low prices, or a trailing average of prices over a number of days. Any such approach should be properly documented and consistently applied. 

[5] Such award features must be designed carefully to achieve compliance with, or exemption from, Section 409A.

[6] But see footnote 2 above regarding the FICA tax special timing rule that may require assessment of FICA taxes on RSUs in the year of vesting rather that at the later, deferred payment date.

[7] See IRM 20.1.4.26.2(5), “Expanded instruction to NSO, stock-settled SAR, and stock-settled RSU. Clarified time frame for settlement,” issued May 26, 2020. 

This article was originally published on July 9, 2020 on ConsensusDocs. It is reprinted here with permission.

It is sometimes overlooked that clauses in contracts requiring performance are not treated the same in cases of breach. There is a distinct difference in construction contracts between clauses that are conditions and clauses that are covenants. This difference determines the remedy a party is entitled to receive upon breach of the obligation. To understand this difference, we must first identify how these clauses are defined.

• “A covenant is a promise to do something (as in a covenant of quiet enjoyment in a deed)”; whereas,
• “[a] condition is a contingency that must be met, otherwise a particular property right could be gained or lost.”[1]

Under generally accepted principles of contract law, the remedies for breaches of covenants and conditions are different. The remedies are as follows:

• For a breach of a condition, the breaching party is not entitled to performance (i.e., payment) by the nonbreaching party.[2]
• For breach of a covenant, the breaching party is entitled to the nonbreaching party’s performance; however, the nonbreaching party is entitled to be compensated for damages resulting from the breach of the covenant.[3]

The classic law school case Jacob & Youngs, Inc. v. Kent[4] provides a good analysis of the distinction. After the completion of a home construction project, it was discovered that the home was constructed with nonconforming pipe. The owner demanded replacement of the pipe, notwithstanding the fact that there was no evidence that the nonconforming pipe was inferior in quality to the pipe specified in the contract. Judge Cardozo, who authored the majority opinion of the court, discussed the distinction between covenants and conditions (sometimes referring to covenants as “dependent promises”). He stated:

There will be harshness sometimes and oppression in the implication of a condition when the thing upon which labor has been expended is incapable of surrender because united to the land, and equity and reason in the implication of a like condition when the subject matter, if defective, is in shape to be returned. From the conclusion that promises may not be treated as dependent to the extent of their uttermost minutiae without a sacrifice of justice, the progress is a short one to the conclusion that they may not be so treated without a perversion of intention. . . . There will be no assumption of a purpose to visit venial faults with oppressive retribution.[5]

The court held that the failure to use the specified pipe was the breach of a covenant rather than a condition. Thus, the owner was not excused from paying for the work (i.e., “oppressive retribution”), but the payment could be reduced to reflect any reduction in value because of the use of the nonspecified pipe.

Due the harsh difference in remedies as noted by Judge Cardoza, conditions are often interpreted as covenants to avoid forfeiture — the surrendering of the right to receive payment over “venial faults.” Since failure to satisfy a condition would prevent a contractor from recovering for work that it performed under the contract, courts may prefer to treat contractual obligations as covenants rather than conditions.[6] This is particularly true when a benefit has been conferred on the owner and nonpayment would be considered inequitable and akin to a forfeiture. As a generally accepted maxim of jurisprudence, equity abhors a forfeiture:

Forfeitures are not favored by the courts, and if an agreement can be reasonably interpreted so as to avoid a forfeiture, it is the duty of the court to avoid it. The burden is upon the party claiming a forfeiture to show that such was the unmistakable intention of the instrument. “A contract is not to be construed to provide a forfeiture unless no other interpretation is reasonably possible.”[7]

A common area where conditions are interpreted as covenants are notice provisions. In California, for instance, notice provisions in contracts can be interpreted as covenants rather than conditions to avoid forfeiture of a contractor’s claim.[8] When the notice requirement is found to be a covenant, the owner is entitled to recover, as an offset against the contractor’s claim, whatever damages the owner actually suffered from not receiving timely notice.[9]

The policy behind treating conditions as covenants is to interpret the contracting parties’ intentions to avoid unusual or inequitable results, to avoid forfeitures, and to avoid placing one party at the mercy of the other.[10] Courts have found that a provision in a contract for forfeiture of any damages for noncompliance with provisions relating to the filing of the claims must be strictly construed against that entity for whose benefit the clause was inserted.[11]

For example, in D. A. Parrish & Sons v. County Sanitation District,[12] the contract required written notice of a claim within 10 days after discovering the factual basis for the claim, and it provided: “The Contractor’s failure to notify the Owner within such ten (10) day period shall be deemed a waiver and relinquishment of any such claim against the Owner.” In refusing to enforce this forfeiture, the court held, “[A] forfeiture clause, such as this, will not only be strictly construed but has been interpreted by this court not to apply to claims arising from breaches of the contract caused by the other party.”

Outside of California, other jurisdictions also interpret notice provisions to avoid forfeiture. Sometimes courts will find that the government entity received “constructive notice,” thereby satisfying the notice condition in the contract. For example, in Welding, Inc. v. Bland County Service Authority,[13] a court found that mention of the claim issues in the progress meeting minutes was found to satisfy the notice requirement. Also, some courts will find that the notice would serve no useful function in the context of the case and therefore would not be considered a condition of the contract.[14]

There are some jurisdictions, however, that will not treat conditions as covenants in an effort to avoid forfeiture. For example, Stone Forest Industries, Inc. v. United States[15] involved a dispute arising out of contracts entered into with the U.S. Forest Service. Each of the contracts contained a provision stating that the purchaser shall file claims against the U.S. Forest Service within certain time limits and that “[f]ailure by Purchaser to submit a claim within these time limits shall relinquish the United States from any and all obligations whatsoever arising under said contract or portions thereof.”[16] The court held that this was “clearly a condition” because “the time limitation is clearly ‘an event, not certain to occur, which must occur . . . before performance under a contract becomes due.’”[17] Additionally, the court held that the time limitation “is not a covenant, as plaintiffs argue, because it does not create a right or duty in and of itself.”[18] The court found that, because the time limitation provision was a condition, and not a covenant, compliance with the time limitation was required before plaintiffs could enforce their refund rights under the contract.

Thus, due to the distinct differences in remedies in breaches of conditions and covenants, provisions in contracts that might be construed as conditions requiring forfeiture should be examined closely with an eye to the law of the contract’s jurisdiction and any equitable principles that may cause courts discomfort in enforcing. 

---

1 John Reily, Covenants vs. Conditions, The Data Advocate (July 25, 2014).

2 See Thomas C. Horne, Arizona Construction Law § 102 (2020).

3 Id.

4 Jacob & Youngs v. Kent, 230 N.Y. 239, 242 (1921).

5 Id.

6 See Thomas C. Horne, Arizona Construction Law § 102 (2020).

7 Universal Sales Corp., Ltd. v. California Press Mfg. Co., 128 P.2d 665, 677 (Cal. 1942).

8 See Cal. Civ. Code §§ 1442, 1670.5 (2020); Restatement (Second) Contracts § 227 (Am. Law Inst. 1981).

9 E.g., Streicher v. Heimburge, 272 P. 290, 294 (Cal. 1928) (“Many cases may be found where the words ‘provided’ or even ‘on condition that’ have been used and nevertheless held to be covenants and not conditions.”).

10 See Cal. Civ. Code §§ 3542 & 3520; Hawley v. Orange County Flood etc. Dist., 211 Cal. Rptr. 478, 480 (Cal. Ct. App. 1963).

11 See Milovich v. Los Angeles, 108 P.2d 960, 965 (Cal. Ct. App. 1941).

12 See D. A. Parrish & Sons v. Cty. Sanitation Dist., 344 P.2d 883, 887 (Cal. Ct. App. 1959).

13 See Welding, Inc. v. Bland Cty. Serv. Auth., 541 S.E.2d 909, 915 (Va. 2001).

14 Sunshine Steak, Salad & Seafood, Inc. v. W. I. M. Realty, Inc. 522 N.Y.S.2d 292, 293 (N.Y. 1987) (“[W]here it becomes clear that one party will not live up to a contract, the aggrieved party is relieved from the performance of futile acts or conditions precedent.”).

15 See Stone Forest Industries, Inc. v. U.S., 26 Cl. Ct. 410, 414 (1992).

16 Id. at 412.

17 Id. at 416-417.

18 Id. at 417.

Executive Summary of FERC Order No. 872: Qualifying Facility Rates and Requirements Implementation Issues Under the Public Utility Regulatory Policies Act of 1978 [1]

I. Overview

On July 16, 2020, the Federal Energy Regulatory Commission (FERC or the Commission) issued Order No. 872, the Commission’s final order revising its regulations implementing Sections 201 and 210 of the Public Utility Regulatory Policies Act of 1978 (PURPA) [2]. This order, which follows a 2016 technical conference on PURPA issues and a September 2019 Notice of Proposed Rulemaking (NOPR) [3], is the first major set of revisions to FERC’s regulations implementing PURPA since they were established through Order No. 69 in 1980.

As FERC explained in the NOPR, the energy landscape has evolved in significant ways since the initial PURPA regulations were established, which includes increased supplies of natural gas, a more matured renewables industry, and the growing presence of non-Qualifying Facility (QF) independent power producers. These and other changes prompted FERC to revise its PURPA regulations, many of which are implemented by the states. These new changes provide additional guidance to state commissions regarding PURPA implementation and rests additional authority in state commissions regarding QF rates and contract terms. These regulatory changes fall into five categories, as outlined below:

1. Rates:
   • In the case of QF power sales contracts and other Legally Enforceable Obligations (LEOs), in addition to continuing to allow states to establish fixed QF rates, FERC granted states the flexibility to set variable rates for QF energy (but not capacity).
   • In the case of QF power sales contracts and LEOs utilizing fixed rates, FERC granted states additional flexibility to establish such fixed rates using projected energy prices during the term of a QF’s contract.
   • In the case of QFs selling on an “as-available” basis within an organized wholesale market, FERC established a rebuttable presumption, rather than a per se rule (as proposed in the NOPR), that locational marginal prices (LMPs) may reflect a purchasing electric utility’s avoided energy costs. Outside of an organized wholesale market, FERC granted states flexibility to set “as available” energy rates at competitive prices from liquid market hubs or calculated from a formula based on natural gas price indices and heat rates.
   • Allows states to utilize transparent and non-discriminatory competitive solicitations to set “avoided costs” for QF energy and capacity sales.
2. One-Mile Rule:
   • Amends the “one-mile” rule to add a new rebuttable presumption that affiliated facilities more than one mile apart but less than 10 miles apart are separate facilities.
   • Maintains the irrebuttable presumption that facilities located one mile apart or less constitute a single facility and creates an irrebuttable presumption that facilities 10 miles apart or more are separate facilities.
3. Obligation to Purchase:
   • Reduces the size threshold from 20 MW to 5 MW for the rebuttable presumption that QFs have nondiscriminatory access to markets.
   • However, FERC confirmed that utilities that were previously granted termination of the mandatory purchase obligation for contracts above 20 MW must reapply with FERC requesting relief from the mandatory purchase obligation for small power production facilities between 5 MW and 20 MW.
4. Legally Enforceable Obligation:
   • Allows states to establish objective and reasonable criteria to determine a QF’s commercial viability and financial commitment to construction before a QF may establish a LEO.
5. QF Self-Certification:
   • Allows parties to protest QF certifications without filing a petition for declaratory order.
   • Clarifies that protests may be made to new certifications, but only to recertifications that make substantive changes to the existing certification.

FERC declined to adopt the proposed rule permitting states with retail competition to allow relief from the PURPA purchase obligation. Instead, FERC clarified that the Commission’s existing PURPA Regulations already require that states, to the extent practicable, must account for reduced loads in setting QF capacity rates.

FERC also rejected arguments from various parties that an environmental analysis under the National Environmental Policy Act of 1969 (NEPA) was required.

In a partial dissent, Commissioner Glick rejected much of the Commission’s Order No. 872 as an “administrative gutting” of its long-standing PURPA implementation regime, chastising the Commission for failing to pursue a more “durable, consensus solution” rooted in promoting competition. In particular, Commissioner Glick argued that the reduction to the rebuttable 20 MW purchase-obligation threshold in Order No. 872 and changes to its avoided cost rate determination violated PURPA’s mandate to prevent discriminatory rate treatment and encourage QF development.

Order No. 872 will go into effect 120 days from its publication in the Federal Register.

II. Summary of Revisions

A. QF Rates

A core aspect to PURPA is the obligation on utilities to purchase QF power at a rate that does not exceed such utility’s “incremental cost…of alternative electric energy,” i.e., the rate that, but for the QF purchase, the utility would otherwise incur by purchasing from another source. This rate, referred to as the “avoided cost” rate, must be both non-discriminatory for the QFs, while also being just and reasonable to the consumers of the electric utility and in the public interest [4]. FERC’s PURPA regulations provide QFs with two options for selling their power at avoided cost rates: (1) selling as much energy as the QF chooses whenever it becomes available (referred to as an “as-available” sale), and (2) selling its output pursuant to an LEO (such as a contract), over a specified term, with the “avoided cost” rate calculated either at the time of delivery, or calculated and fixed at the time the LEO is incurred [5]. 

Order No. 872 is notable, therefore, in so far as it fundamentally reforms how states are allowed to set “avoided costs” rates for QFs—both in the “as-available” and LEO contexts. In particular, and as summarized below, FERC revised its PURPA regulations to permit states to incorporate competitive market forces in setting QF rates.

1. Granting States the Flexibility to Require Variable Energy (but not Capacity) QF Rates in QF Power Sales Contracts and Other LEOs

Under long-standing PURPA regulations, if a QF chooses to sell energy and/or capacity pursuant to a contract, the QF would be provided the option of receiving the purchasing electric utility’s avoided cost that was calculated and fixed at the time an LEO is incurred [6]. In the NOPR, FERC proposed to revise its regulations to allow states the flexibility to require QF energy rates to vary during the term of a QF contract [7]. Avoided capacity costs calculated at the time the contract or LEO is incurred would still remain fixed, however. As FERC explained in the NOPR, record evidence at the time suggested that fixed QF energy rates more often led to QFs receiving greater than avoided-cost rates [8].

The proposal drew criticism and support from a variety of parties, with proponents generally arguing that fixed rates, coupled with the overall decline in energy prices, led to improper customer subsidization of QFs, while opponents argued that Congress and court precedent supported long-term fixed energy rates as being necessary to encourage QF development [9].

In Order No. 872, FERC adopted the NOPR proposal without modification. As FERC explained, the primary impetus for the change was “to better comply with Congress’s clear instruction in PURPA that the Commission may not require QF rates in excess of a purchasing utility’s avoided costs.” [10] In support, FERC argued first, that the record evidence demonstrates that long-term fixed avoided cost energy rates are often well above avoided-costs without balancing out over time [11]. Second, although FERC acknowledged the obligation in PURPA for commission regulations to encourage QF development, this obligation, FERC argued, “is bounded” by the general prohibition that QF rates may not exceed avoided costs [12]. Third, FERC generally rejected claims that allowing variable QF energy prices would lead to discrimination against QFs [13], and argued that, even if PURPA guaranteed QF financeability, variable avoided cost energy rates would still allow QFs to obtain financing [14].

In adopting the NOPR proposal, FERC also rejected requests to allow for variable avoided capacity costs, reasoning that the cost for avoided capacity is determined at the time of the capacity purchase obligation, which is different from variable energy prices determined at the time of delivery. FERC also declined requests to specify a minimum required contract length and to adopt additional criteria for establishing avoided capacity costs, leaving such decisions up to existing state processes [15].

FERC cautioned, however, that states may not “toggle” back and forth between requiring fixed and variable QF energy rates. Rather, “QFs are entitled to the certainty that once a state has made its choice with respect to a particular QF’s contract or LEO, that QF’s contract or LEO is not subject to change during the term of that contract or LEO except by mutual consent.” [16]

2. Granting Additional Flexibility to Establish Fixed QF Energy Contract Rates Based on Forecasts

In addition to allowing variable energy rates in QF contracts, for QF contracts utilizing fixed energy rates, FERC proposed to permit a QF to request a fixed energy rate for the entire term of the contract based on a forward price curve—i.e., forecasted energy prices at the times of delivery over the life of the contract. This proposal generally received widespread support.

FERC adopted the proposed reform in Order No. 872 [17]. FERC clarified that a state may use competitive market prices and/or variable energy rates in the context of a more fixed estimated avoided cost energy rate (together with a fixed avoided capacity rate) that is determined at the time an LEO or contract is incurred. This fixed energy rate component, FERC explained, could be a single rate, based on the amortized present value of forecast energy prices, or it could be a series of specified rates that change from year-to-year (or other periods) in future years. According to FERC, states may establish the applicable energy rate(s) for the QF for the entire term, or the rate may change from year-to-year (or some other period) of the contract at the time the LEO is incurred [18].

3. Granting States Inside and Outside RTOs/ISOs Additional Flexibility in Setting “As Available” QF Energy Rates

In the NOPR, FERC also proposed various reforms related to “as available” QF sales—both inside and outside organized wholesale markets operated by Regional Transmission Operators (RTOs) and Independent System Operators (ISOs).

For QFs selling their energy on an as-available basis in an RTO/ISO, FERC proposed in the NOPR, and adopted in Order No. 872, to permit states to set such as-available QF energy rates at the Locational Marginal Price (LMP) calculated at the time of delivery [19]. In contrast to the NOPR, however, FERC declined to adopt a rule that LMP was a “per se” appropriate measure of avoided costs, but instead that there was a presumption of appropriateness, that could be rebutted by an aggrieved party (such as a QF). 

For QFs selling their energy on an as-available basis outside of an RTO/ISO, FERC proposed, and adopted in Order No. 872, to allow states to set such as-available QF energy rates at delivery-based competitive prices from liquid market hubs [20], or, in the absence of such a hub, calculated from a formula based on natural gas price indices and heat rates [21]. In either case, FERC noted that states must first find that the chosen option adequately represents the purchasing utility’s avoided cost for as-available energy [22].

In the case of liquid market hubs, FERC also confirmed that (1) states with access to more than one such market may average or develop a formula to derive an as-available avoided energy cost; (2) states must determine that a liquid market hub is sufficiently liquid that its prices are competitive; and (3) the market hub price may need to be subject to adjustments to account for transmission costs the electric utility would incur [23]. In the case of formula-based natural gas price indices, FERC confirmed the formula should include recovery of variable O&M costs [24]. FERC also rejected calls to consider other, non-combined cycle natural gas, technologies, reasoning that states already have that flexibility—and nothing in the rule foreclosed that option—and that focusing on combined cycle technology was appropriate for the proposal, given that such generation makes up a large portion of the country’s generation fleet [25]. 

4. Granting States Flexibility to Set Energy and Capacity Rates based on Competitive Solicitations

In the NOPR, the Commission also proposed to permit states to set avoided energy and/or capacity rates using competitive solicitations (i.e., RFPs). In Order No. 872, FERC adopted this proposal, with several modifications and clarifications. First, FERC expanded on the NOPR minimum criteria for what constitutes a transparent and non-discriminatory solicitation. Without passing judgment on previously-conducted solicitations, FERC concluded that, going forward, a PURPA-compliant solicitation must be conducted in a process that includes, but is not limited to, the following factors: (i) the solicitation process is an open and transparent process that includes, but is not limited to, providing equally to all potential bidders “substantial and meaningful” information regarding transmission constraints, levels of congestion, and interconnections, subject to appropriate confidentiality safeguards; (ii) solicitations must be open to all sources, to satisfy that purchasing electric utility’s capacity needs, “taking into account the required operating characteristics of the needed capacity”;(iii) solicitations are conducted at “regular intervals”; (iv) solicitations are subject to oversight by an “independent administrator”; and (v) solicitations are “certified” as fulfilling the above criteria by the relevant state regulatory authority or nonregulated electric utility through a post-solicitation report [26]. 

Second, FERC clarified that competitive solicitations must also be conducted in accordance with the principles in Allegheny Energy Supply Co., LLC, 108 FERC ¶ 61,082, at P 18 (2004) [27]. FERC then made certain other clarifications from the NOPR, including:

• Participants must be given “substantial and meaningful information regarding transmission constraints, levels of congestion, and interconnections, subject to appropriate confidentiality safeguards.” [28]
• Utilities must provide state commissions, and make publicly available, a post-solicitation report that summarizes the solicitation results and demonstrates non-preference for the utility and its affiliates [29].
• The phrase “taking into account the operating characteristics of the needed capacity” necessarily allows utilities to procure the type of capacity that they need, but it should not be used to effectively exclude QF generation [30].
• FERC declined to be overly prescriptive about what constitutes “regular intervals” or an “independent administrator,” but did clarify that “certification” required a written, formally-issued finding by the relevant state commission that the solicitation was PURPA-compliant [31].

B. The One-Mile Rule

Under FERC’s current PURPA regulations, there is an irrebuttable presumption that facilities owned by the same person(s) that use the same energy resource, but are more than one mile apart from each other, are located on separate sites and are therefore separate facilities [32]. This is often referred to as FERC’s “one-mile rule”. 

In the NOPR, FERC proposed to change the one-mile rule by creating a new rebuttable presumption that facilities more than one mile apart and less than 10 miles apart are separate facilities [33]. This new presumption would allow any interested party to intervene and file a protest to argue that two facilities (which would be more than one mile apart and less than 10 miles apart) should be treated as a single facility. 

Commenting parties were divided as to whether QF developers are currently circumventing the current one-mile rule by strategically siting small power production facilities that use the same energy resource more than one mile apart. FERC noted that some parties had expressed that concern while others argued there was no evidence of any such “gaming” of the current one-mile rule [34]. Commenters also questioned the potential impact the one-mile rule revisions could have on other Federal Power Act (FPA) and Public Utility Holding Act (PUHCA) exemptions [35].

Order No. 872 adopts the NOPR proposal to change the one-mile rule. Thus, if a small power production facility seeking QF status is located more than one mile but less than 10 miles from any affiliated small power production QFs that use the same energy resource, it will be presumed to be at a separate site [36]. Any such QFs located one mile or less will be irrebuttably presumed to be at the same site, and any such QFs located 10 miles or more will be irrebuttably presumed to be at separate sites [37]. While the rebuttable presumption can be protested by any interested person or entity, FERC also noted that it could act sua sponte [38].

FERC confirmed the one-mile rule would not remove or amend other exemptions that a QF is entitled to, but that the one-mile rule would be used to determine whether affiliated facilities were at the same site and if a QF did not meet the 80 MW size limit “for whatever reason” (including a failure to meet the revised one-mile rule) then it would not be a QF [39]. 

FERC also explained that a small power production facility seeking QF status may provide additional information in its certification (or recertification) to preemptively defend against a challenge by identifying certain physical and ownership factors that affirmatively show its facility is at a separate site from affiliated small power production QFs that use the same energy resource that are more than one but less than 10 miles from its facility [40]. Finally, FERC defined “electrical generating equipment” and confirmed that any such equipment must be measured from the edge of the equipment closest to the affiliated small production QF’s nearest electrical generating equipment [41]. 

C. Relief from Purchase Obligation in Competitive Retail Markets—Not Adopted

In the NOPR, FERC proposed to amend Section 292.303(a) of the PURPA regulations, which generally requires utilities to purchase “any energy and capacity which is made available from a qualifying facility,” [42] to provide that a utility’s obligation to purchase power from QFs may be reduced to the extent the purchasing electric utility’s supply obligation has been reduced by a state retail choice program. In Order No. 872, FERC declined to adopt its NOPR proposal, but instead clarified that its existing PURPA regulations already require that states, to extent practicable, account for reduced loads in setting QF rates [43].

FERC received comments both in support and in opposition to its proposal. Commenters in opposition argued, among other things, that FERC lacked statutory authority to implement its proposal, and that FERC’s rationale for the rule was unclear [44]. Other commenters requested additional clarification from FERC, including on states’ authority to exempt traditional or alternative retail suppliers from PURPA’s mandatory purchase obligation [45].

In declining to adopt its proposed amendments to Section 292.303(a), FERC explained that Section 292.304(e)(3) already does, and will continue to allow states, when setting avoided cost rates, to take into account “the ability of the electric utility to avoid costs, including the deferral of capacity additions.” [46] FERC stated that it regards this existing regulation as allowing a state to consider reductions in a purchasing electric utility’s provider of last resort obligations under state law [47]. FERC further clarified that it did not intend for this to be reflected as a MW-for-MW reduction (or increase) based on yearly changes in load, and that Section 292.304(e)(3) “does not and may not serve to terminate a purchasing utility’s mandatory purchase obligation under PURPA section 210(a).” [48]

D. Self-Certification Process

Under the current PURPA regulations, QFs file a FERC Form 556 to certify that they meet the requirements for QF status [49]. If a QF makes any material modification to its facility, it cannot rely upon its certification and must re-certify with the updated information [50]. FERC does not verify any of the information provided, and has declined to make any changes to the self-certify process in past orders to provide any such verification.

In the NOPR, FERC proposed to change section 292.207(a) of its PURPA regulations to allow interested persons to protest QF self-certifications and recertifications without having to file a petition for a declaratory order or paying any associated fees [51]. FERC also proposed to change its Form 556 to allow QFs to proactively provide information that would be considered in any challenge pertaining to the changes to the one-mile rule regulations. These changes include providing all affiliated facilities within 10 miles rather than affiliated QFs within one mile, as required before. 

Several commenters raised the issue of grandfathering existing QFs for their future recertifications arguing, among other things, that the application of the new rule to existing QFs would effectively bar the transfer or sale of existing assets that were lawfully qualified under the one-mile rule but would not pass the 80 MW aggregate threshold under the new rule [52]. Other implementation questions were posed focusing on the administrative burden and litigation risk imposed by the new rule.

Order No. 872 largely adopted the NOPR proposal but did provide for limited grandfathering. When the rules become effective, protests may be made to new certifications (both self-certifications and applications for FERC certification) but only to recertifications that make substantive changes to the existing certification [53]. FERC agreed that recertifications that were needed for non-substantive changes should not subject existing QFs to potentially losing their QF status [54]. FERC also adopted its proposal to expand the affiliated facility information collected on Form No. 556 from one to 10 miles [55]. FERC explained that this information was necessary to implement the new rules. As mentioned above, applicants with affiliated small power production QFs greater than one mile and less than 10 miles from the entity seeking QF status may, if they choose, explain why the QFs should be considered to be at separate sites by providing the relevant physical and ownership factors.

Any protest filed under the new rules must be made 30 days from the filing of a QF’s Form No. 556, and the party filing any such protest bears the burden to demonstrate that the facility does not satisfy the requirements for QF status [56]. If this prima facie burden is met, then the burden shifts to the applicant submitting the QF self-certification or recertification to demonstrate that the certification is warranted [57]. FERC will issue an order within 90 days of the filing of a protest and if FERC declines to take action on the protest it will be deemed denied and the certification will remain effective [58]. 

E. Obligation to Purchase

PURPA is perhaps most known for its mandatory purchase obligation, but FERC’s PURPA regulations permit an electric utility to file an application requesting relief from the mandatory purchase obligation if FERC determines that the QF has nondiscriminatory access to certain markets to sell its power. This provision was added by the Energy Policy Act of 2005, and was intended to reflect the fact that organized electric markets provide alternative markets for sales by QFs. The current PURPA regulations include a rebuttable presumption that QFs with a net power production capacity at or below 20 MW lack nondiscriminatory access to any such markets [59].

In the NOPR, FERC proposed to reduce the size threshold at which the presumption of nondiscriminatory access to a market attaches from 20 MW to 1 MW for small power production facilities (but not cogeneration facilities) [60]. FERC reasoned that in light of the maturation of organized markets, such a reduction was consistent with Congress’s intent to relieve electric utilities of their obligation to purchase when a QF has nondiscriminatory access to competitive markets [61]. FERC proposed to exclude cogeneration facilities from the revisions because the owners of cogeneration facilities might not be as familiar with energy markets and the technical requirements for such sales. 

FERC noted numerous comments addressing the proposal. Parties opposed to the reduction argued, among other things, that there was a lack of evidentiary support or sufficient explanation for FERC’s change in policy and a substantial increase in administrative burdens [62]. Comments supporting the revisions pointed to the widespread participation in RTO/ISO markets that has taken place since 2005 [63]. The National Association of Regulatory Utility Commissioners (NARUC) suggested that FERC allow utilities to rely upon RFPs and liquid market hubs to establish eligibility to terminate the mandatory purchase obligation, while other comments suggested that utility-sponsored RFP programs were not robust enough to simulate a competitive market [64].

Recognizing some of the challenges that QFs near 1 MW have in participating in markets, FERC modified its proposal and changed the size threshold to 5 MW instead of 1 MW [65]. Thus, the rebuttable presumption that QFs with a net capacity at or below 20 MW do not have nondiscriminatory access to those markets is reduced to 5 MW for small power production facilities (but remains unchanged for cogeneration facilities). FERC stated it would consider on a case-by-case basis whether a properly run RFP or competitive acquisition process could also justify the termination of the mandatory purchase obligation [66].

FERC also confirmed that utilities that were previously granted termination of the mandatory purchase obligation for contracts above 20 MW must reapply with FERC requesting relief from the mandatory purchase obligation for small power production facilities between 5 MW and 20 MW [67]. FERC noted that QFs over 5 MW and under 20 MW can still attempt to rebut the presumption, and make their case that they do not truly have nondiscriminatory access to a market and therefore should still be entitled to a mandatory purchase obligation [68]. 

F. Legally Enforceable Obligation

The current PURPA regulations specifically provide that QFs can choose to have their rates based on the avoided cost calculated at the time of delivery, or at the time an LEO is incurred. The regulations do not provide any details, however, about when or how an LEO is established, which has been a frequent area of litigation.

The NOPR proposed to amend Section 292.304(d)(3) of the PURPA regulations to require that QFs demonstrate that a proposed project is commercially viable, and that the QF has a financial commitment to construct the proposed project pursuant to objective, reasonable, state-determined criteria to be eligible for an LEO [69]. FERC intended the revisions to ensure that no electric utility obligation was triggered for a QF project that was not sufficiently advanced in its development and for which it would be unreasonable for a utility to include in its resource planning while at the same time ensuring that the purchasing utility does not unilaterally and unreasonably decide when its obligation arises [70].

Among the arguments opposing the LEO changes, some commenters stated that developers cannot obtain financing without the financial commitment of a power purchase agreement (PPA) or LEO from the utility and that the new requirement would lead to a substantial reduction in the number of QFs. Others argued that the new requirement would not narrow the range of divergent LEO tests currently adopted by states. Commenters supporting the proposal thought the revisions appropriately balanced the interests of utilities and developers and provided states more clarity about the LEO while still preserving their ability to develop criteria specific to local planning needs. Numerous commenters also requested additional modifications to the LEO proposal [71].

Order No. 872 adopted the NOPR proposal requiring states to establish objective and reasonable criteria to determine a QF’s commercial viability and financial commitment to construction before a QF can establish a LEO [72]. FERC confirmed states have flexibility as to what constituted an acceptable showing of commercial viability and financial commitment but noted that the factors must be within the control of the QF [73]. Thus, states could reasonably require QFs to take meaningful steps to obtain site control or file an interconnection application with the appropriate entity but could not require QFs to obtain site control or obtain a PPA [74]. 

FERC described the LEO revisions as “raising the bar to prevent speculative QFs from obtaining LEOs” without “establishing a barrier for financially committed developers seeking to develop commercially viable QFs.” [75] FERC disagreed with those arguing that the revisions would cause a substantial reduction of QFs, stating that objective criteria will protect QFs against onerous requirements that hinder financing [76]. FERC also confirmed that the LEO changes do not affect the viability of any executed contact or LEO in place as of the effective date of the final rule [77].

G. Environmental Analysis

In the NOPR, FERC explained that it was not possible to determine environmental effects related to the proposed revisions to the PURPA regulations given numerous uncertainties and therefore environmental review under the National Environmental Policy Act of 1969 (NEPA) was not needed [78]. Several commenters argued that FERC erred in failing to conduct such a review, pointing out, for example, that FERC undertook a NEPA analysis when it first implemented PURPA [79].

In Order No. 872, FERC found that no Environmental Assessment (EA) or Environmental Impact Statement (EIS) to evaluate the final rule was required, as the final rule does not propose, authorize, or define the scope and limits of any potential energy infrastructure, and in the alternative, FERC found that this rule was categorically excluded due to the fact that the revisions to PURPA were clarifying, corrective, and procedural in nature and do not substantially change the effect of a regulation being amended [80].

III. Commissioner Glick Partial Dissent

In a lengthy partial dissent, Commissioner Glick explained that, despite supporting certain aspects of Order No. 872, such as the revision allowing stakeholders to protest a QF’s self-certification, he believed that the Order as a whole is “not just poor public policy, but also arbitrary and capricious agency action.” [81] Specifically, he argued that Order No. 872 fails to encourage the development of QF facilities and prevent discrimination against QFs, as statutorily mandated under PURPA. In support of his conclusion, Commissioner Glick pointed to a number of specific aspects of the Order that he viewed as problematic.

• Avoided Cost Rate: With respect to the Order’s elimination of the fixed energy rate, or contract option, Commissioner Glick highlighted his belief in the “essential role” fixed-price contracts play both in the financing of QF facilities and in helping to ensure QFs are guaranteed full cost recovery on par with the cost recovery guarantees afforded to vertically integrated utilities. As a result, he dismissed as “hogwash” the Commission’s arguments that its removal of the fixed energy rate option will encourage QF development and continue to satisfy PURPA’s prohibition on discriminatory rates. Second, Commissioner Glick disagreed with the Order’s rebuttable presumption for setting the avoided cost rate at the LMP as discriminatory, noting his concern that short-term prices may not reflect the long-term marginal energy costs avoided by purchasing utilities [82].
• 20 MW Threshold: Commissioner Glick asserted that Order No. 872 reduces the threshold for the rebuttable presumption that QFs operating in RTO/ISOs have non-discriminatory access to competitive markets from 20 MW to 5 MW without explanation as to how the barriers arrayed against small QFs in organized markets have dissipated. As a result, he concluded that the Commission’s policy reversal is “toothless” and “arbitrary and capricious.” [83]
• NEPA Review: Commissioner Glick also challenged the Commission’s characterization of revisions set forth in Order No. 872 as “mere corrective changes” that would qualify them for categorical exemption from environmental review under NEPA [84].

Finally, on a more macro level, Commissioner Glick expressed dismay over the Commission’s election to, in his words, “administratively gut” its implementation of PURPA, instead of modernizing its PURPA regulations by promoting market competition. In particular, Commissioner Glick pointed to a proposal released by the National Association of Regulatory Utility Commissioners—which urged the Commission to establish criteria for vertically- integrated utilities outside of RTOs/ISOs to terminate its must-purchase obligation based on competitive solicitations—as a more “durable, consensus solution” than the Order [85]. 

The effective date of Order No. 872 will be 120 days from the date of the Federal Register publication.

 

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[1] DISCLAIMER: THIS SUMMARY IS PROVIDED FOR INFORMATIONAL PURPOSES ONLY AND DOES NOT CONSTITUTE LEGAL ADVICE ON ANY PARTICULAR QUESTION, NOR SHOULD IT BE CONSTRUED TO CREATE AN ATTORNEY-CLIENT RELATIONSHIP.

[2] Qualifying Facility Rates and Requirements Implementation Issues Under the Public Utility Regulatory Policies Act of 1978, 172 FERC ¶ 61,041 (2020) (Order No. 872).

[3] Qualifying Facility Rates and Requirements Implementation Issues Under the Public Utility Regulatory Policies Act of 1978, Notice of Proposed Rulemaking, 168 FERC ¶ 61,184 (2019) (NOPR).

[4] Order No. 872 at P 96.

[5] Id. at P 97.

[6] Id. at P 232. An LEO gives a QF the enforceable right to require utilities to purchase the QF’s power at avoided cost rates.

[7] Id. at P 234 (explaining NOPR proposal).

[8] Id. at P 235.

[9] Id. at PP 245-252.

[10] Id. at P 256.

[11] Id. at PP 283-293.

[12] Id. at PP 295-296

[13] Id. at P 302.

[14] Id. at PP 335-336.

[15] Id. at PP 357-360.

[16] Id. at P 353

[17] Id. at P 227

[18] Id. at P 227.

[19] Id. at P 151

[20] Id. at P 189.

[21] Id. at P 211.

[22] Id. at P 190 (setting out factors for states to consider in making a determination regarding whether a liquid market hub represents the purchasing utility’s avoided cost for as-available energy); id. at P 212.

[23] Id. at P 201.

[24] Id. at P 211

[25] Id. at P 214.

[26] Id. at P 427.

[27] Id. at P 430.

[28] Id. at P 431.

[29] Id. at P 432.

[30] Id. at P 433.

[31] Id. at P 436.

[32] Id. at P 458.

[33] Id. at P 460.

[34] Id. at P 470.

[35] Id. at P 512.

[36] Id. at P 466. FERC modified the NOPR proposal slightly to shift from focusing on identifying “separate facilities” to identifying whether facilities are at “the same site” to better match its statutory language. See id. at P 476. 

[37] Id. at P 466.

[38] Id. at P 460.

[39] Id. at P 514.

[40] Id. at P 480. See also id. at P 509 (listing the specific physical and ownership factors adopted by FERC).

[41] Id. at PP 521-23. FERC defines “electrical generating equipment” to include all boilers, heat recovery steam generators, prime movers, electrical generators, photovoltaic solar panels and/or inverters, fuel cell equipment and/or other primary power generation equipment, but excluding equipment used for gathering energy to be used in the facility.

[42] 18 C.F.R. § 292.303(a).

[43] Order No. 872 at P 457.

[44] Id. at PP 444-48.

[45] Id. at PP 449-55.

[46] Id. at PP 456-57.

[47] Id.

[48] Id.

[49] Id. at P 525.

[50] Id. at P 552.

[51] Id. at P 525.

[52] Id. at P 531.

[53] Id. at P 547.

[54] Id. at P 550. FERC also determined that its recertification requirement would be unduly burdensome for rooftop solar PV developers, and is therefore requiring any such developers to recertify quarterly. Id. at P 559.

[55] Id. at P 591. FERC modified its proposal slightly by including the expanded information in item 8a rather than adding another line item as 8b.

[56] Id. at P 526.

[57] Id. at P 557.

[58] Id. at P 566.

[59] Id. at PP 118-121.

[60] Id. at P 597.

[61] Id. at P 598.

[62] Id. at PP 602-13.

[63] Id. at PP 614-23.

[64] Id. at P 648.

[65] Id. at P 625.

[66] Id. at P 662.

[67] Id. at P 645.

[68] Id. at PP 636, 641 (listing factors to rebut the presumption to access to market).

[69] Id. at P 663.

[70] Id at P 664.

[71] Id. at PP 676-83.

[72] Id. at P 684.

[73] Id. at PP 684-85.

[74] Id. at P 685.

[75] Id. at P 688.

[76] Id. at P 689 (citing FERC orders pertaining to state LEO standards).

[77] Id. at P 694.

[78] Id. at P 702.

[79] Id. at PP 704-09.

[80] Id. at 710-42.

[81] Partial Dissent, P 7.

[82] Id. at PP 9-16.

[83] Id. at PP 20-24.

[84] Id. at PP 25-26.

[85] Id. at P 29.

The Federal Communications Commission (FCC) issued a noteworthy order on June 25, 2020, in its continuing interpretation of the Telephone Consumer Protection Act (TCPA). In its order, the FCC confirmed many courts’ existing interpretation of the TCPA, noting that any text platform that requires manual entry of telephone numbers and manual launching of texts on a one-by-one basis is not an automatic telephone dialing system (ATDS). The FCC also waded into the debate regarding random or sequential number generation, stating that whether a telephone is an “autodialer turns on whether such equipment is capable of dialing random or sequential telephone numbers without human intervention.” 

Background

P2P Alliance, a coalition of providers and users of peer-to-peer text messaging services, petitioned the FCC in 2018 for clarity regarding text messaging platforms that most P2P members use. The Alliance described the P2P platforms as “ones that enable two-way text communication, require a person to manually send each text message one at a time, and enable the sender to exercise discretion regarding the content and other features of the text messages.” The Alliance further confirmed that the platforms do not have the capacity to store or produce telephone numbers to be called, using a random or sequential generator. Instead, the platform “requires a person to actively and affirmatively manually dial each recipient’s number and transmit each text message one at a time.” The Alliance emphasized the fact that their text message communications are the result of a relationship between the sender and recipient, “where the recipient has indicated his or her consent to receive such messages by providing a contact number to which P2P Alliance messages are delivered.”

The Order

In its order, the FCC confirmed that a text message system that “requires a person to actively and affirmatively manually dial each recipient’s number and transmit each message one at a time and lacks the capacity to transmit more than one message without a human manually dialing each recipient’s number,” then it is not an ATDS. While courts have disagreed on what constitutes an ATDS with regard to random or sequential number generation, courts on both sides have still found that human intervention reigns supreme. The FCC order reinforced this conclusion. According to the FCC, where a party can show that its telephone system or text message platform requires human beings to manually initiate each call one at a time, that system is not an ATDS.

The FCC order also waded into the debate regarding random or sequential number generation. There is currently a Circuit split as to how to interpret the random or sequential number generation requirement in the TCPA’s ATDS definition. Some courts, like the Ninth Circuit, have held that “storage” of telephone numbers alone – without random or sequential number generation – is enough to satisfy the first prong of the ATDS definition. Other courts, like the Seventh Circuit, have concluded that a telephone without the capacity to generate numbers randomly or sequentially cannot be an ATDS, even if it is capable of storing numbers. The FCC is aware of the debate raging in these courts and solicited public comment in light of the Ninth Circuit’s decision in Marks v. Crunch San Diego, LLC.

In its order, the FCC did not explicitly state that it was wading into the debate regarding random or sequential number generation. But the order’s language implies otherwise. According to the FCC’s order, “whether the calling platform or equipment is an autodialer turns on whether such equipment is capable of dialing random or sequential telephone numbers without human intervention.” This statement is significant. If the FCC believed storage of telephone numbers was enough to satisfy the first prong of the ATDS definition, there would be no reason for the FCC order to reference “random or sequential” telephone numbers. But, it chose to do so, nonetheless. This suggests that the FCC – perhaps implicitly – is endorsing the majority rule that a telephone does not constitute an ATDS unless it is capable of generating random or sequential numbers, regardless of whether the telephone can also store numbers to be called.

“Take Aways”

Although the order is relatively short, it provides several important “take aways.”

• The FCC confirmed that a system is not an ATDS if it is not capable of dialing numbers without a human “actively and affirmatively dialing each one.”

• The FCC clarified that whether a platform or system is able to send texts or make calls to a considerable volume of telephone numbers is not dispositive of the ATDS issue. In doing so, the FCC emphasizes human intervention over volume of calls or messages.

• The FCC rejected the notion that policy concerns should invade the interpretation of the TCPA’s ATDS definition. For example, consumer groups argued that telemarketers “would immediately gravitate to P2P systems as a way to evade the TCPA’s restrictions on unwanted calls.” The FCC responded that “[t]he TCPA does not and was not intended to stop every type of call.”

• The FCC suggested that random or sequential number generation is an ATDS requirement, although it left a more definitive interpretation of that issue for another day.

In sum, the FCC’s order confirms the analysis coming from the courts for the past two years – human intervention is a powerful argument against a telephone system constituting an ATDS. As the number of human steps a telephone system requires to launch a call or text increases, the likelihood that the system is an ATDS decreases. In addition, the FCC provided new fodder for arguing that random or sequential number generation is a requirement for a system to constitute an ATDS.

As the wave of reopening orders sweeps across the country, businesses see a light at the end of the tunnel. That light, however, in many instances is still yellow, and may be so for some time to come. Serious restrictions continue to hamper the habitual functioning of America’s businesses, customers have dwindling cash to pay for goods, supplies are restricted or cut, and social distancing practices and protocols reduce productivity. Companies, therefore, continue to take a closer look at their contracts to determine their rights, including whether force majeure and other provisions may still be invoked.

This article is set forth in three parts. First, it describes general considerations in deciding whether and how to invoke force majeure, encouraging contracting parties to take a holistic view of the entire contractual relationship. Second, the article addresses best practices in drafting force majeure notices, including general points to consider, what form a notice should take, and what to include in the notice. This portion of the article includes a draft template that can be tailored to the specific business and legal context. Third, this article describes general notices, a tool often used in construction contracts, as an alternative to specifically addressing force majeure. This section recognizes that there are often instances in which other contractual remedies are more attractive than force majeure.

General Considerations

When drafting a notice related to a force majeure event, it is important to keep in mind a few general themes, including the objectives, contract terms, an understanding of the force majeure event, the business relationship, and, as always, the potential for litigation.

• Objectives. It is imperative to determine the objective that the force majeure notice will serve. What are you trying to accomplish with the force majeure notice? Is an extension of time sought? Is the recovery of prolongation costs in addition to schedule relief needed? While many have knee-jerk reactions to serve a notice under the contractual force majeure provision the instant an unforeseen event impacting performance occurs, it is critical to make sure the objective of the notice is clear before sending. Keep in mind that typical force majeure provisions may only offer an extension of time to perform. There may be, however, certain circumstances in which invoking force majeure is not the best route to accomplish the objective, particularly when other contractual remedies afford more practical or attractive solutions to meet your objectives.
• Contract terms. Force majeure notices are contractually driven. The form and contents of the notice are governed by the force majeure provision in the contract. However, after establishing objectives, what if the remedies available in the force majeure provision do not match those objectives? Does the contract contain other clauses that provide a better remedy more in line with your objectives? Knowing all of the nuances of the contract becomes critical to determining your course of action. It is also crucial to consider the contractual options of your contract opponent. Will you trigger a reason to terminate or withhold payment? Will you trigger a claim of anticipatory breach? Be familiar with all contractual terms before drafting any force majeure notice.
• Understand the impacts caused by the force majeure event. This may seem obvious, but it is necessary to consider the possible scenarios occurring at the beginning of the force majeure event, and afterwards as well. There have been numerous federal and state shutdown and stay-at-home orders issued, and now we are beginning to see reopening orders being implemented. As the shutdown and stay-at-home orders are lifted, there will be a “ramp up” period in which businesses will open, but not be operating at full capacity. Will this ramp-up period, when an emergency declaration is no longer in place, still impact one’s ability to perform under the contract? Moreover, what impact will social distancing have on your business for the weeks or months after the technical force majeure event ends? Offices may operate at half-staff, stores may limit the number of guests allowed at a time, and factories may limit the number of staff at the facility. Considering all of the possible impacts of the force majeure event will be key in determining what to include in a notice.
• The business relationship. It is always important to strictly abide by contractual notice requirements. However, the strength of your business relationship can impact how your notice is received. A longstanding business partner may accept a simple contract-compliant notice that generally explains the delays and increased costs due to the force majeure event, while other more litigious business partners may require a more detailed explanation. There may be other outside laws, regulations or considerations that impact the force majeure notice, including whether there are administrative notice requirements, whether the parties conduct other business together, and whether the force majeure event has impacted that business as well. While it is important to understand the contract between the parties in drafting a force majeure notice, it is just as important to have a complete understanding of the business relationship and the people involved.
• The potential for litigation. As always, keep in mind that there could be litigation resulting from the force majeure event. Accordingly, the notice should be drafted as if giving notice for any other legal purpose, with a long-term view in mind. Be flexible with the notice, and avoid limiting rights and remedies to prevent hamstringing legal positions down the road. Remember, courts have held that “[t]he failure to give proper notice is fatal to a defense based upon a force majeure clause requiring notice.” Sabine Corp. v. ONG Western, Inc., 725 F. Supp. 1157, 1168-69 (W.D. Okla. 1989) (dismissing defendant’s force majeure affirmative defense for failure to provide sufficient and proper notice of invoking force majeure).

With that background, here are some best practices when drafting force majeure notices.

Drafting Force Majeure Notices

Form and Service of Notice

When issuing either a force majeure notice or more general notice of delay, there are a few practical concepts to keep in mind regarding what form the notice should take. These three tips will ensure your notice is proper and serves its intended purpose.

• Comply with the contract terms. The general form of the notice will be guided by the terms of the contractual force majeure provision. This will include the means of communicating the notice, the way in which the notice is to be served, and the time in which the notice must be served. Parties typically must strictly adhere to the requirements set forth in notice provisions to be effective.
• If impossible, then substantially comply. There may be instances, however, when strict compliance is impossible. For example, if personal service is required, governmental restrictions limiting business operation may prevent a party from providing personal service within the time period allotted. Under these circumstances, substantial compliance may excuse failure to achieve literal compliance with the contract terms. Courts have held that a reasonable effort to provide notice as soon as possible may constitute valid notice, even if it is not in strict compliance with the contractual terms. See Toyomenka Pac. Petroleum, Inc. v. Hess Oil Virgin Islands Corp., 771 F. Supp. 63, 68 (S.D.N.Y. 1991) (granting summary judgment and holding that six-day delay in providing notice did not prevent defendant from force majeure defense because defendant made reasonable effort to give notice as soon as possible).
• Keep and maintain documentation of all notice activities. Where strict compliance is impossible to achieve, keep careful records of all attempts to serve and provide notice. Complete records will be critical to combat later arguments that a notice was ineffective because it was not served in compliance with the contract.

Substance of a Force Majeure Notice

After identifying your objectives, understanding the event, analyzing the business relationship, and reviewing your contract, you decide that invoking force majeure is the best option. Each of the below points should be included in your force majeure notice. Including these points should ensure your force majeure notice will constitute valid notice under your contract.

• Identify the force majeure event. Regardless of how obvious or apparent the force majeure event may be, the force majeure event must be specifically identified in the notice. It is common for contractual force majeure provisions to specifically reference events like government acts, pandemics, epidemics or health emergencies. Some force majeure provisions are more general, and may only reference events like “acts of God.” If the event does not fall squarely within an enumerated event covered by the force majeure clause, mirror the language of the force majeure clause when explaining the event. If intent on invoking the force majeure clause, cite specifically to the section and language of the force majeure provision in the contract when detailing the event. Keep in mind, however, you should do this only if you have gone through the contract and concluded that invoking force majeure is the best option. If other, better remedies are available in the contract, then including reference to the specific force majeure section may limit your potential rights and remedies during a litigation. Thus, you should include a citation to the specific force majeure clause only if force majeure is the desired course and you do not plan to ever seek additional forms of relief. Otherwise, as discussed further below, your notice should not include reference to the force majeure provision to avoid limiting future rights.
• Explain how the force majeure event impacts performance. The notice should provide an explanation of how the force majeure event is preventing performance of contractual obligations and how long it is expected to impact performance. Reference sections in the contract that are specifically impacted, such as clauses detailing work, deliverables or services to be provided. Characterize and quantify the loss of time, ability or money suffered as a result of the force majeure event. Include attempts taken to mitigate, and, if possible, consider providing supporting documentation. Keep in mind, however, that if there is an expected insurance or government investigation into the force majeure event, providing documentation such as photos should only be done if absolutely necessary.
• Identify the relief the force majeure notice seeks. Here is where knowing your contract and having clear goals come into play. Are you seeking an extension of time to perform? Are you seeking termination of the contract? While the available remedies may be contract-dependent, the notice should include the relief sought.
• Include adequate assurances. In order to avoid any claims for anticipatory breach, it may be necessary to include adequate assurances of performance once the force majeure event subsides. Include how and when performance will be fulfilled once possible. This is especially important if only a suspension of performance is sought, and not termination of the contract. Note that updates will be given if circumstances change, and keep the possibility of continuing the contractual relationship if feasible. If there are no alternatives and termination is sought, notify and memorialize any attempts made to perform, and be clear in noting the force majeure event’s impact on the ability to perform.
• Do not limit rights. Circumstances change. Litigation may arise. The notice may be an exhibit to a pleading. Be sure to reserve all rights and remedies, both contractually and at law, in the notice. In addition, consider whether you might be able to rely on the common law doctrines of impossibility, impracticability or frustration of purpose, and make reference to each in your notice to ensure they are not waived.
• Supplement as more information becomes available. Keep the lines of communication open. Advise that regular updates will be given. Show good faith in the attempts to perform and mitigate damages. This will go a long way for the business relationship and in potential litigation, especially during times of uncertainty.

Force Majeure Notice Template

To go along with the best practices, a template force majeure notice that can be used to invoke a force majeure provision is available here. It is consistent with the guidance and best practices above. It should be tailored depending on the terms of the contract, the relationship of the parties, the type of force majeure event, and the ultimate goals in issuing a force majeure notice. Keep in mind, however, that while the template serves as a guiding framework, the notice must ultimately be consistent with the terms of the contractual requirements and the law of the relevant jurisdiction.

General Notice Instead of Force Majeure Notice

In certain circumstances, particularly in construction contracts, the remedies afforded in the force majeure clause may not align with the objectives for issuing a force majeure notice. Moreover, there may be other provisions that provide better relief than force majeure. One example would be if the force majeure provision only affords an extension of time to perform while other provisions may permit the recovery of lost profits or other prolongation costs. If there is any question regarding which provision should apply, a broader, more general notice may be more practicable in order to avoid limiting available rights and remedies should a dispute arise. Here are some key points to consider when drafting a general notice of delay as opposed to a force majeure notice.

• Identify the event. Similar to a force majeure notice, the general notice should identify the event causing the delay or hindering performance. It should not call the event a “force majeure event” or reference the specific force majeure section of the contract. Doing so may give the appearance of simply invoking the force majeure clause instead of a more beneficial clause in the contract. The notice should instead establish the date when the event impacting performance began and provide dates when it is expected that the event will subside or cease interference with performance.
• Explain how the event impacts performance. Provide a similar explanation as to how the event is preventing performance. Provide assurances that, once possible, performance under the contract will be completed.
• Define the relief sought. Explain the relief sought as a result of the event. When calculating or determining the relief sought, be sure to take into account all relief sought by any “downstream” entities reporting to you as well. For example, if a general contractor needs 50 additional days to complete a task due to an unforeseen event, and a subcontractor informed the general contractor that it will need an extra 20 days to perform, the general contractor, in putting together its notice of delay, should request 70 days to encompass what will be needed for the project to be completed.
• Do not limit rights or remedies. When it is unclear which clause should be invoked, do not limit your remedies to those in the force majeure clause. Do not cite to a specific provision for which you are providing notice when providing a general notice of delay. Because the goal is to provide a general notice for all possible applicable provisions offering relief in the contract, citing to a specific provision may waive the future exercise of other clauses. To simultaneously provide contractual notice of delay without citing to a specific provision in the contract, explain that the notice will be “in satisfaction of all notice requirements in the contract.” Finally, include a reservation of rights and remedies both within the contract and at law.
• Provide “downstream” notices “upstream.” Particularly in construction, the entire supply chain, including suppliers, subcontractors and general contractors, may be impacted by a similar event. For anyone who has to pass notice “upstream,” it is imperative to provide any and all notices received from “downstream” parties. For example, a supplier may provide a notice to a subcontractor, who also provides notice to the general contractor. In order to give the property owner or developer a more complete understanding of the impact of the event, and to ensure you provide notice for all of the relief sought, it is critical to incorporate notices received from all subcontractors and suppliers in your upstream notice to the owner or developer.