On June 26, 2019, in a much-anticipated ruling, the U.S. Supreme Court refused to overturn the long-standing Auer deference standard, which provides that courts should defer to agencies’ interpretations of their own rules if those rules are ambiguous. Kisor v. Wilkie, 588 U.S. __ (2019). The case was brought by a Marine veteran who sought retroactive disability payments from the U.S. Department of Veterans Affairs (VA) dating back to the early 1980s to cover treatments for post-traumatic stress disorder, which he had allegedly developed as a consequence of his service in the Vietnam War. The VA denied the request and the Board of Veterans’ Appeals—an administrative tribunal within the VA— affirmed this decision based on its interpretations of the VA’s rules. The U.S. Court of Appeals for the Federal Circuit concluded that the VA regulation at issue was ambiguous and, citing Auer v. Robbins, 519 U.S. 452 (1997), deferred to the Board’s interpretation of the rule. The Marine veteran argued to the U.S. Supreme Court that it should overrule Auer and abandon the deference that Auer
and its progeny gave to agencies interpreting their own rules.

Writing for the majority, U.S. Supreme Court Justice Elena Kagan stated that “Auer deference retains an important role in construing agency regulations.” Justice Kagan emphasized, however, that Auer deference has its limits and is “sometimes warranted and sometimes not.” It is warranted only after “traditional tools” of construction, whereby “a court must ‘carefully consider’ the text, structure, history, and purpose of a regulation, in all the ways it would if it had no agency to fall back on.” Justice Kagan stated that “[d]oing so will resolve many seeming ambiguities out of the box, without resort to Auer deference.” But even where an ambiguity is found, only reasonable agency interpretation will merit deference. The rule being interpreted must also be the “official position” of the agency, rather than an ad hoc statement conveniently tailored to fit a particular situation, and the agency’s interpretation must “implicate its substantive expertise.” Finally, to receive Auer
deference, the “rule must reflect fair and considered judgment.”

Justice Kagan relied heavily on stare decisis, a legal doctrine by which courts are obligated to respect the precedent established by prior judicial decisions. She emphasized the broad reach of Auer deference and the chaos that would ensue if reversed: “It is the rare overruling that introduces so much instability into so many areas of law, all in one blow.” Justice Kagan also noted that because the case did not involve a constitutional issue, Congress remains free to amend or enact a law that would effectively overrule Auer.

The case was remanded to the Federal Circuit to determine whether Auer deference applies in light of the Court’s opinion. Though five justices concurred with Justice Kagan’s holding, Justice Neil Gorsuch and Chief Justice John Roberts each offered their own reasoning in support of the holding, with Justice Gorsuch expressing significant skepticism about Auer deference. He explained that while the rule stands, “the doctrine emerges maimed and enfeebled—in truth, zombified.”

Although the facts of the case concerned veterans’ benefits, the Court’s ruling has broader implications for federal agencies, especially those in the environmental and energy regulatory arena. As agencies like the U.S. Environmental Protection Agency and U.S. Department of the Interior continue to reshape policies surrounding issues including climate change, natural resource development, access to public lands, and endangered species, the degree of deference that judges afford to agency interpretations becomes one of the most critical factors in determining the outcome of a court challenge to an agency’s decision on such issues.

The outcome of Kisor v. Wilkie was closely watched, as the case presented an opportunity for the Court to substantially reduce the power of federal agencies by diminishing the deference afforded to them, thereby allowing courts to more frequently second-guess agencies. The case was also was seen as a litmus test of the Court’s appetite to reevaluate the related and similarly controversial doctrine of Chevron
deference. Chevron deference applies to agency interpretations of ambiguous statutes. Ultimately, the Court opted to maintain the status quo. On the one hand, the new limits might restrain agencies tempted to stretch their interpretation of certain regulations, and the Court’s refusal to overturn Auer provides continued consistency for agencies and practitioners familiar with the doctrine’s existing bounds and applications. On the other hand, as Justice Gorsuch stated in his concurrence, the opinion serves as “more a stay of execution than a pardon,” thanks to the failure of the Court to find a consensus on why Auer deference should be maintained. This disunity opens the door for future challenges to agency deference, and the Court will almost certainly have to address the agency deference standard again soon. The regulated community should continue to watch this area of jurisprudence carefully, as an erosion of agency deference would have significant implications for their operations.

If you have any questions regarding this decision or how it may affect your business, please contact Randy Dann, Shalyn Kettering, or Lucas Satterlee.

On March 13, 2019, in Edgar v. Anadarko Petroleum Corp., No. H-17-1372, 2019 WL 1167786 (S.D. Tex. Mar. 13, 2019), the U.S. District Court for the Southern District of Texas dismissed a shareholder lawsuit against Anadarko Petroleum Corporation (“Anadarko”) and several of its executives because the plaintiff failed to show that Anadarko’s management knowingly misled investors about the company’s safety compliance.

Anadarko is a publicly traded oil and gas exploration and production company with operations primarily in Texas, the Gulf of Mexico, and Colorado. On April 17, 2017, a home exploded near an Anadarko well in Firestone, Colorado, killing two people and critically injuring another. On April 26, 2017, Anadarko announced that one of its wells might have been involved in the explosion and that the company planned to shut down 3,000 similar wells in Colorado. Anadarko’s stock price fell by 4.7% the next day. On May 2, 2017, the Firestone-Frederick Fire Department confirmed the link between Anadarko’s well and the Firestone explosion. A return line that was connected to the Firestone well leaked methane into the home’s drains, which exploded when a hot water header was being installed. By abandoning the flowline without disconnecting and sealing it, Anadarko had violated Colorado Oil and Gas Conservation Commission Rule 1103. On May 3, 2017, Anadarko’s stock price fell by 7.7%.

The Iron Workers Benefit and Pension Fund, as lead plaintiff for a putative class of investors, sued Anadarko and its executive committee, alleging that the defendants violated Sections 10(b) and 20(a) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and Rule 10b-5 thereunder by making material misrepresentations in Anadarko’s public filings and other communications with respect to the company’s compliance with health, safety, and environmental laws and regulations. The defendants moved to dismiss the complaint, which the district court granted without prejudice but with leave for the plaintiff to amend its claims, citing, among other points, the plaintiff’s failure to explicitly and precisely set out why each purportedly misleading statement was false or misleading and why the speaker knew, or recklessly disregarded the fact, that the statement was misleading.

The plaintiff filed an amended complaint, alleging that the defendants made the following material misrepresentations in violation of Sections 10(b) and 20(a) of the Exchange Act and Rule 10b-5: (i) a fact sheet dated February 8, 2016, authorized or approved by Anadarko’s vice president of corporate communications, stating that Anadarko’s Wattenburg, Colorado operations center “[p]rovides real-time remote-monitoring capabilities for 6,800+ wells” and “[e]nables employees to shut in wells remotely”; (ii) Anadarko’s annual report on Form 10-K for the fiscal year ended on December 31, 2015, filed with the Securities and Exchange Commission (the “SEC”), signed by the company’s chief executive officer, stating that the company “believes that it is in material compliance with existing environmental and occupational health and safety regulations”; (iii) health, safety, environment, and sustainability overviews dated March 12, 2016, and March 3, 2017, and signed by the chief executive officer and vice president for the health, safety, and environment division of the company, stating that “Anadarko operates its global onshore and offshore operations in compliance with the applicable laws and associated regulations”; (iv) Anadarko’s registration statement on Form S-3 filed with the SEC on August 12, 2016, incorporating the 2015 Form 10-K; and (v) an underwriting agreement filed with the SEC in September 2016, representing to an underwriter that Anadarko has “been in compliance with all applicable [laws] and other legally enforceable requirements relating to the prevention of pollution, the preservation of environmental quality, the protection of natural resources, or the remediation of environmental contamination.” The defendants again moved to dismiss.

The central issue in Edgar v. Anadarko was whether the amended complaint had sufficiently alleged scienter as to Anadarko’s executives under Section 10(b) of the Exchange Act and Rule 10b-5, where “[t]he required state of mind is an intent to deceive, manipulate, or defraud, or severe recklessness.”

In its published opinion, the court analyzed the alleged misrepresentations of each Anadarko executive, starting with those contained in the fact sheet authorized or approved by Anadarko’s vice president of corporate communications. The amended complaint alleged that the statements in the fact sheet about remote-monitoring capabilities were false because half of Anadarko’s Wattenberg Field wells in Colorado were not equipped for any sort of remote interaction, a fact that was described in PowerPoint slides for, and discussed at, one or two of the biannual meetings, the majority of which the corporate communications executive attended. The court determined that the amended complaint (i) did not properly plead that the executive had knowledge of the statement’s falsity and (ii) improperly relied on the executive’s title to allege that he approved or authorized the fact sheet, without alleging specific facts linking the executive to the challenged statements contained therein. Accordingly, the court concluded that allegations did not support an inference that the executive “made” the challenged statement as required for liability under Rule 10b-5 and that even if the executive had made the statements in the fact sheet, the amended complaint failed to allege facts sufficiently supporting a strong inference that he did so with scienter.

The court then held that the amended complaint failed to allege facts supporting a strong inference that the chief executive officer or vice president for the health, safety, and environment division of Anadarko had a motive to make false, material misstatements to investors. The court noted that to sufficiently plead that a defendant engaged in securities fraud to inflate the price of a company’s stock, a plaintiff must allege that the defendant profited from the inflated stock value or stock offerings. The amended complaint contained no allegation that either officer personally profited from Anadarko’s stock offering completed in 2016. Moreover, the court determined that a general motive to improve a company’s financial condition, one universally shared by all companies and executives, does not suffice to establish an inference of scienter of fraud. According to the court, the facts presented in the amended complaint at most supported an inference that the vice president for the health, safety, and environment division of Anadarko should have known that the company’s Colorado operations were unsafe and, therefore, in violation of Colorado law, but any such inference or theory erroneously “conflates safety with legal compliance” and improperly “reduces scienter to negligence.” As to Anadarko’s chief executive officer, the court found that the amended complaint contained no allegation that the executive attended any particular meeting at which state-specific well and flowline concerns were discussed, only speculation that such a meeting might have occurred.

The court dismissed the amended complaint with prejudice and without leave for the plaintiff to further amend its claims, noting that “further amendment would be futile.” Although the holding in Edgar v. Anadarko is fact-specific, the case demonstrates that to withstand a motion to dismiss, a complaint involving allegations of fraud must plead with particularity the circumstances constituting the alleged fraud, including with respect to the element of scienter. Notwithstanding the plaintiff’s failure in this case to allege facts supporting a strong inference of scienter, issuers should be careful about making general statements of compliance with respect to applicable laws because any such statements can form the basis of a shareholder lawsuit (and with slightly different facts, one that could withstand a motion to dismiss or result in liability).

If you have any questions regarding this decision or how it may affect your business, please contact Edward Shaoul.

On January 14, 2019, the Colorado Supreme Court issued its decision in Martinez v. Colo. Oil & Gas Conservation Comm’n, 2019 CO 3, ___ P.3d ___. In a unanimous decision, the Court reversed the decision by the Court of Appeals and concluded that the Colorado Oil and Gas Conservation Commission (COGCC or the “Commission”) properly declined to engage in rulemaking to consider a proposed rule that would have precluded all new oil and gas development unless it could occur “in a manner that does not cumulatively impair Colorado’s atmosphere, water, wildlife, and land resources, does not adversely impact human health, and does not contribute to climate change.”

In 2013, Xiuhtezcatl Martinez and six other youth activists (Respondents) submitted the proposed rule at issue in this case. Their concerns included the cumulative effects of oil and gas production on climate change, driven by carbon dioxide emissions from fossil fuels. Following extensive public comment and a hearing, the COGCC unanimously decided not to engage in rulemaking on the petition. The Commission reasoned, among other things, that the proposed rule would be inconsistent with the Colorado Oil and Gas Conservation Act (the “Act”), C.R.S. § 34-60-100 et seq., and that it was already working with the Colorado Department of Public Health and Environment (CDPHE) to address these issues and that other COGCC priorities took precedence over the proposed rulemaking.

The Commission’s denial of the petition was upheld by the Denver District Court, which agreed with the COGCC that the Act requires the Commission to “strike a balance between the regulation of oil and gas operations and protecting public health, the environment, and wildlife resources.” The case was then appealed to the Colorado Court of Appeals. In a split 2- 1 decision, the Court of Appeals reversed the District Court in Martinez v. Colo. Oil & Gas Conservation Comm’n, 2017 COA 37, __ P.3d __. The majority relied upon language in the Act stating that it is in the public interest to “[f]oster the responsible, balanced development . . . of oil and gas . . . in a manner consistent with protection of public health, safety, and welfare, including the environment . . . .” In the majority’s view, this language does not create a balancing test but indicates instead that oil and gas development is subject to the protection of public health and the environment and that the latter takes precedence over the former. The dissent deferred to the COGCC’s longstanding interpretation of the Act as creating a balancing test, and it noted that the language in question comes from a legislative declaration that does not alter the agency’s authority.

The Colorado Supreme Court granted review, and its decision focuses on two issues: 1) how to construe the Act’s legislative declaration; and 2) whether the COGCC’s ongoing work with the CDPHE and its other priorities provided an alternative justification for not initiating rulemaking. Most of the Court’s decision focuses on the first issue.

The Court found that the Act’s legislative declaration is reasonably susceptible to multiple interpretations and therefore ambiguous. The State of Colorado asserted that the COGCC is required to balance oil and gas development with the protection of public health and the environment, pointing to the phrase “consistent with” to require such action. The Respondents use the same “consistent with” phrase to argue that it establishes a mandatory condition that must be satisfied.

To resolve the ambiguity, the Court turned to the language and history of the Act. The Court construed the language and history neither to create a balancing test between oil and gas development and public health and environmental protection nor to make the latter a condition precedent for the former. Instead, the Court viewed the legislative declaration “as reflecting a legislative intent to promote multiple policy objectives, including the continued development of oil and gas resources and the protection of public health and the environment, without conditioning one policy objective on the satisfaction of any other.” The Court further explained that the Act seeks to “minimize adverse impacts to public health and the environment while at the same time ensuring that oil and gas development . . . could proceed in an economical manner.” The Court synthesized its interpretation of the Act as follows: “[T]he pertinent provisions make clear that the Commission is required (1) to foster the development of oil and gas resources, protecting and enforcing the rights of owners and producers, and (2) in doing so, to prevent and mitigate significant adverse environmental impacts to the extent necessary to protect public health, safety, and welfare, but only after taking into consideration cost-effectiveness and technical feasibility.“

Based upon the Court’s reading of the Act, it held that the COGCC properly declined to initiate rulemaking. As the Court explained, the proposed rule was inconsistent with the Act because it would require “the Commission to condition one legislative priority (here, oil and gas development) on another (here, the protection of public health and the environment).”

With respect to the second issue, the Court held that the Commission also properly declined to engage in rulemaking on the proposed rule because it was already working with CDPHE to address many of the underlying concerns and because other regulatory priorities took precedence. In ruling on this issue, the Court emphasized that agencies have substantial discretion in deciding whether to undertake rulemaking and that a high standard applies to any attempt to overturn such a decision. The Court concluded that the Commission had properly exercised its discretion in this case because “it was collaborating with the CDPHE to address the matters implicated by [the] proposed rule” and because it had determined that “other priorities took precedence over the proposed rulemaking.”

Although the Court did not identify those priorities, during the two years after the Commission denied the rulemaking petition, it “cleaned up” various regulations, increased penalties for violations and updated enforcement procedures, simplified the complaint process, imposed new flood protection requirements, implemented the Governor’s Task Force recommendations, and issued 15 new policies and guidelines, all of which directly or indirectly protect public health and the environment.

The Martinez decision clarifies the meaning of the Act’s legislative declaration and substantially upholds the COGCC’s interpretation of its authority. As discussed at length by the Court, the declaration recognizes multiple policy objectives for the COGCC to pursue, including both oil and gas development and public health and environmental protection. As a practical matter, this interpretation will make it difficult for litigants to rely on the declaration to challenge agency decisions. As has historically been the case, the declaration will provide little or no ammunition for litigants claiming that the COGCC has improperly allowed or restricted oil and gas development. Such claims will instead have to rely on the substantive provisions of the Act and the facts.

This decision also appears to reflect the Colorado Supreme Court’s confidence in the COGCC’s exercise of its authority. Since 2012, four matters concerning the COGCC have reached the Court: Colo. Oil & Gas Conservation Comm’n v. Grand Valley Citizens’ All., 2012 CO 52, 279 P.3d 646 (Colo. 2012); City of Longmont v. Colo. Oil & Gas Conservation Comm’n, 2015 CO 667, 369 P.3d 573 (Colo. 2016); City of Fort Collins v. Colo. Oil & Gas Conservation Comm’n, 2015 CO 668, 369 P.3d 586 (Colo. 2016); and Martinez, 2019 CO 3, ___ P.3d ___. In all of these cases, the Court upheld the COGCC’s actions or agreed with its position. Notably, three of these decisions were unanimous, and the other was decided by a vote of 6-1. This suggests that the agency is responsibly performing its job.

The effect of the decision will likely crystalize over time and will be the subject of debate in the Colorado Legislature this session. Some members of the Legislature have already indicated that they intend to introduce legislation to amend the Act and seek to undo the Court’s decision. Governor Polis indicated his support for further action, stating that he was “disappointed by [the Court’s] ruling, it only highlights the need to work with the Legislature and the Colorado Oil and Gas Conservation Commission to more safely develop our state’s natural resources and protect our citizens from harm . . . .” “Gov. Polis Responds to the Colorado Supreme Court’s Decision” [Press Release], January 15, 2019.

If you have any questions regarding the decision or how it may affect your business, please contact Dave Neslin or Greg Nibert, Jr.

On November 1, 2018, the Colorado Department of Public Health and Environment (CDPHE) issued a new General Permit for Stormwater Discharges Associated with Construction Activities—COR400000 (2018 General Construction Permit). The 2018 General Construction Permit will take effect on April 1, 2019, replacing the current general permit that has been in place since 2007.

This Legal Alert briefly summarizes some of the key aspects of the 2018 General Construction Permit, including its applicability and coverage, notable revisions, and important timing considerations. This Alert also discusses the Colorado Environmental Online Services (CEOS) platform, which was launched by CDPHE on November 1, 2018.

Legal Alert Key Takeaways

• CDPHE issued a new General Permit for Stormwater Discharges Associated with Construction Activities (COR400000) on November 1, 2018, which becomes effective on April 1, 2019.
• The new permit introduces several significant changes to the requirements of the existing 2007 permit, including issues current and new permittees need to be aware of and comply with beginning April 1, 2019.
• CDPHE also launched the Colorado Environmental Online Services (CEOS) web-based permitting platform; and starting April 1, 2019, all CDPHE permit applicants and existing permittees—not just those applying for coverage under the 2018 General Construction Permit—must use CEOS for permit actions.

2018 General Construction Permit Basics

The 2018 General Construction Permit is issued pursuant to Colorado’s Discharge Permit System (CDPS), which implements Section 402 of the Federal Clean Water Act. Coverage is generally required for the discharge of stormwater from construction activity—including construction associated with oil and gas and mining activities, in addition to most other industries—that will disturb at least one acre of land or that is part of a common plan of development or sale that will disturb at least one acre. Most construction projects in Colorado will be covered by the new permit, which provides a common set of terms and requirements applicable to stormwater management at covered projects. Under certain circumstances, a project will need an individual CDPS permit, with terms tailored to the specifics of the project.

The 2018 General Construction Permit, like the prior version, authorizes stormwater (and certain related non-stormwater) discharges associated with construction activities to waters of the State. The chief requirements of the permit include implementation of “control measures” (formerly called “best management practices”) to minimize pollutant discharges from construction sites, development and implementation of a Stormwater Management Plan (SWMP), and regular site inspection and reporting to ensure compliance with permit terms.

Significant Changes in the 2018 General Construction Permit

The 2018 General Construction Permit introduces several significant (as well as a variety of less significant) changes to the existing requirements of the 2007 permit, including:

• Key Change in Terminology: The new permit replaces the well-known term “Best Management Practices” (BMPs) with “Control Measures” (CMs). CMs are defined as “[a]ny [BMPs] or other method used to prevent or reduce the discharge of pollutants to state waters,” and may include BMPs and “other methods such as the installation, operation, and maintenance of structural controls and treatment devices.” In general, CMs must follow “good engineering, hydrologic and pollution control practices,” and be designed to control all potential pollutant sources and to prevent pollution or degradation of state waters. According to CDPHE, CMs encompass a broader category of pollutant reduction practices that a permittee may implement to comply with the new permit.
• Co-Permittees Approach: Owners and operators are now required to be co-permittees, whereas only one was required to obtain coverage under the 2007 permit. CDPHE anticipates this approach will increase commitment by both owners and operators to comply with the requirements to obtain a permit and meet permit requirements.
• CM Requirements: The 2018 General Construction Permit adds several requirements for specific structural and non-structural CMs. Most significantly, these include requirements to (1) maintain pre-existing vegetation within 50 feet of receiving State waters; (2) implement temporary stabilization measures (e.g., tracking, terracing, ripping/grooving, mulching) on portions of the site where land disturbing activities have ceased for at least 14 days; and (3) perform corrective actions (beyond mere maintenance) where CMs are inadequate, which was not an express requirement under the 2007 permit.
• SWMP Requirements: Additional SWMP requirements under the new permit include the requirement to (1) list on the SWMP the qualified stormwater manager responsible for the site; (2) provide additional details in the SWMP’s Site Description and Site Map; and (3) revise the SWMP within 72 hours of certain changes at the site. The 2018 General Construction Permit also incorporates flexibility into the SWMP submission requirement, allowing for its completion and submission at any time prior to commencement of construction (rather than prior to applying for permit coverage, as required under the 2007 permit).
• Site-Inspections: The initial site inspection now must occur within seven days of construction commencement. For subsequent inspections, in most cases, permittees can choose between (1) at least one inspection every seven days; or (2) at least one inspection every 14 days, if post storm-event inspections are conducted within 24 hours after the end of any precipitation/snowmelt event that causes surface erosion. All inspections must be performed by the qualified stormwater manager.
• Construction Dewatering: Discharges of uncontaminated groundwater to land (i.e., construction dewatering), which were expressly allowed under the 2007 permit, are no longer covered in the 2018 General Construction Permit. According to CDPHE, such discharges were removed because generally they will be covered by and authorized under the agency’s “Low Risk Discharge Guidance Policy, Water Quality Policy 27 – Uncontaminated Groundwater to Land” and/or a separate general permit, and therefore do not need be covered under the 2018 General Construction Permit.

The above-described and other changes to the permit are discussed in detail in the COR400000 Fact Sheet issued by CDPHE with the 2018 General Construction Permit.

Timing

• Current Permittees: Projects with an existing permit certification under the 2007 permit do not need to apply for coverage under the 2018 General Construction Permit, as permit coverage will be automatically transferred as of March 31, 2019 to the new permit. However, it is important for current permittees to understand the terms of the 2018 General Construction Permit, and begin making any necessary changes now, as the new terms will control project operations on April 1, 2019, with no additional grace period for compliance.
• New Permittees: Between now and March 31, 2019, new permittees are required to submit applications for coverage under the 2007 permit, and any such projects will be automatically transferred to the 2018 General Construction Permit as of March 31, 2019. It is important to keep in mind, however, that the deadline for compliance with the new permit is less than five months away. Any new projects starting between now and the April 1 effective date should consider structuring the project’s stormwater program to also meet the terms of the new permit. After March 31, 2019, all projects must apply for coverage under the 2018 General Construction Permit using the CEOS electronic platform discussed below.

CEOS

CEOS, which was launched by CDPHE on November 1, 2018, is a web-based platform that allows permittees to interact with CDPHE’s environmental programs via a single, secure web portal. Users can apply and pay for required permits and upload permit-related documents like site plans and inspection reports via CEOS. Likewise, CDPHE can use the portal to process permit-related requests and otherwise communicate with applicants and permittees. Starting April 1, 2019, all CDPHE permit applicants and existing permittees, not just those applying for coverage under the 2018 General Construction Permit, must use CEOS for permit actions. With respect to the 2018 General Construction Permit, this will include applying for coverage under the new permit, modifying site maps, changing site contacts, and providing notice of permit violations.

Conclusion

We have seen an increase in stormwater enforcement actions in the last year in Colorado and throughout the U.S. In some cases, the U.S. Environmental Protection Agency (EPA) has stepped in to enforce stormwater compliance in the absence of state action. The issuance of the 2018 General Construction Permit, and its upcoming effective date, may further increase scrutiny on construction stormwater management practices for Colorado projects, particularly during the next summer construction season when the new permit is in full effect. As such, existing projects should start preparing for compliance with the 2018 Construction General Permit now, and new projects should design their stormwater management programs with an eye towards the new permit, even if the planned start date precedes April 1, 2019.

If you have any questions regarding the 2018 General Construction Permit—or stormwater regulation and permitting in general—please do not hesitate to contact the authors of this Legal Alert or other members of the Davis Graham Environmental Practice Group.

Multiple studies have confirmed that at least 97 percent of all civil cases settle before trial. The percentage of cases involving multi-million-dollar damage claims that will be decided by a jury is even higher. Cases against big businesses with large footprints and concerns over public perception, higher still. Large corporations, especially those with recognizable and dominant brands, fear the spotlight of jury trials and the potential disaster verdicts that receive so much publicity. But for many companies, the pendulum may have swung too far in favor of settlement. As a result, companies end up paying significant sums for cases that could be won at trial, or at least could result in a verdict for less than the settlement demand. Worse still, companies build a reputation as an easy mark that will settle even weak and unjustified cases, encouraging yet more lawsuits. Settlement is certainly the best option in some cases. But it shouldn’t be the only option, even where a well-funded plaintiff can take a big-dollar damage claim to a jury.

Case Study

Davis Graham recently defended a major oil company facing environmental contamination claims brought by a group of property owners claiming their land and water had been contaminated by the company’s Superfund site. The landowners had deep local roots, were well-funded, and were represented by big-name plaintiffs’ lawyers. Our oil company client, which had experienced a series of recent environmental problems (both local and national) that generated enduring negative publicity, no longer had meaningful operations in the state, and there was no dispute the contamination on the plaintiffs’ property had come from the company’s Superfund site. The plaintiffs initially asserted claims in the hundreds of millions, but they were reduced significantly by the judge’s pretrial rulings. Nonetheless, the plaintiffs presented a claim for $25 million in compensatory damages to the jury, plus punitive damages, which could be as much as 10 times compensatory damages in this jurisdiction. Based on these facts alone, the case might seem like an obvious one to settle—the equities appeared unfavorable, the exposure was significant, and a trial would be long, expensive, and public. And there were opportunities to settle: a pre-complaint meeting, a court-ordered mediation, and on the eve of trial. Although the plaintiffs’ settlement demands were aggressive, our client was capable of paying such a settlement without a material effect on the company’s finances, and had settled many such cases before.

However, we believed there was good reason a jury would not award the plaintiffs the amount they were demanding to settle. We vetted these assumptions carefully, using most of the tools identified above, including a mock trial exercise where two separate jury panels returned verdicts. Both mock juries awarded some money to the plaintiffs, but significantly below the settlement demand. Confident in our risk assessment, and with a fully informed client, we tried the case over three weeks to a jury in federal court. The real jury decided the case even more favorably for our client, returning a complete defense verdict.

While the results of a trial can never be predicted with complete accuracy, we believe the result in this case vindicated our assessment of the client’s risk—which was confirmed not just by the outcome, but also by our post-verdict interviews with the jurors, where many of them echoed comments we heard from our mock jurors and focus-group participants. While a different jury may have returned a different and less favorable verdict, we think our risk assessment accurately predicted that most juries would have returned a verdict lower than the plaintiffs’ settlement demand, which drove the decision to try the case.

Assessing the Risk

When confronted with a lawsuit, every company, no matter the size or industry, will need to make a careful assessment of the risk involved with going to trial. Below are the strategies, considerations, and tools that can be used when faced with such litigation.

• Open, frank communication about risk and exposure
• Early assessment of settlement value and strategy
• Reassessment of settlement value and strategy at regular intervals during the case
• Holistic assessment of settlement value
• Success at trial, not just legal defenses
• Intangible factors, not just facts and law
• Client’s risk tolerance—both monetarily and otherwise

Assessment tools

• Venue and jury pool research
• Jury consultants
• Surveys
• Focus groups
• Peer review
• Mock trial
• Mediation

The European Union’s General Data Protection Regulation (“GDPR”) goes into effect on May 25, 2018. It imposes multimillion dollar fines on violators and purports to apply to U.S. companies, including companies outside the technology industry with no physical presence in the EU.

This Legal Alert provides some practical guidance as to how U.S.-based companies can reduce the risk of becoming the subject of an EU governmental enforcement action or a private civil suit alleging GDPR violations. This is only a general explanation and does not consider individual circumstances, which could significantly affect the best course of action for you. If you have questions about how the GDPR may apply to your own circumstances, please contact one of the Davis Graham Tech Group attorneys listed to the left of this Alert.

1. What is the GDPR?

The GDPR is an unprecedented increase in the privacy protections afforded to individuals who are either residents of, or physically present within, the EU or the EEA¹(“EU Individuals”). The GDPR imposes new, strict rules regarding the collection, processing, storage, transfer, return, and use of any information that can be used, alone or together, with other publicly available information, to identify EU Individuals (“personal data”). The GDPR applies when that personal data is provided to or otherwise possessed by companies or persons in the context of either (i) offering or selling goods or services to, or (ii) monitoring the behavior of, EU Individuals. Personal data includes even publicly available information, such as names or email addresses of individuals. If an EU Individual can be identified, directly or indirectly, by an identifier, such as a name, identification number, location, picture, or physical, physiological, genetic, mental, economic, cultural, or social identity, it is personal data subject to the GDPR.

2. Who could violate the GDPR?

The GDPR purports to bind “controllers” (tech and non-tech companies that obtain personal data for business use) and “processors” (generally tech companies collecting, aggregating, analyzing, or otherwise processing the data) even if they have no physical presence in the EU. For example, the GDPR is triggered when someone in the U.S. obtains personal data of an EU Individual by (a) accepting an online order from anyone while they are in the EU; (b) accepting an online order from an EU resident while the EU resident is in the U.S.; (c) accepting an in-person order of an EU resident in the U.S.; (d) receiving an application for membership, employment, or another similar relationship from an EU Individual, online or in person; or (e) accepting a name or email address from an EU Individual through an online form, account registration, or similar action. Any of these routine actions, among others, might result in a violation of the GDPR unless appropriate steps are taken.

3. Does this mean that I should stop doing business with EU Individuals?

No, but it means that, beginning May 25, you should start dealing with them differently. U.S. companies necessarily gather personal data in every commercial transaction with an EU Individual (e.g., credit card purchases). The gathering of personal data in that context is almost always exempt from the GDPR. On the other hand, the retention of that personal data is not exempt after the commercial necessity of using the personal data for the contract has passed. At that point, the GDPR consent requirements kick in.

U.S. companies routinely keep personal data of customers, members, and other counterparties in various databases for future use, such as marketing, newsletters, and other purposes. The retention of such personal data of EU Individuals, including data obtained before May 25, 2018, is the principal target of the GDPR.

4. What do I need to do by May 25 to become GDPR compliant?

You should confirm that each EU Individual for whom you already have personal data provides to you (or, if you are a “processor,” to the relevant “controller”) a “GDPR-valid” consent to your retention and use of that data. The controller should reach out directly to each EU Individual for that consent. If you are only a “processor,” you must confirm that the relevant controller has done so. Getting these consents will go a long way toward establishing that you are not already in violation of the GDPR when the law goes into effect.

Admittedly, determining the EU Individuals for whom you have personal data anywhere — in a database, in paper records, in individual computers, tablets, or mobile phones — is a daunting task by itself. Having to contact each of them and get their “GDPR-valid” consent before May 25 makes the urgency of this requirement apparent.

5. What is a “GDPR-valid” consent?

The GDPR defines consent as being “freely given, specific, informed and unambiguous.” The EU Individual must positively opt in, via a written statement or oral statement, to your retention of personal data and the specific uses of that data. A GDPR-valid consent cannot be buried in a lengthy Privacy Policy or Terms of Use on your website, or in a long, written contract. It must be a separate assent dealing only with your retention and use of personal data. It cannot be bundled with other agreements. “Consent by silence” is invalid. It cannot be full of obtuse language or legalese but must clearly explain, using plain language, all uses and purposes for the personal data you are retaining, including consent to use processors and sub-processors, if applicable.

6. What if I can’t get “GDPR-valid” consent by May 25?

To be certain you are following the GDPR, you should destroy all personal data of EU Individuals for whom you don’t have a “GDPR-valid” consent. This duty arises as soon as you no longer have a valid commercial purpose to retain the personal data that is directly related to the original contract or transaction by which you collected the data. If and to the extent you need to retain data relating to pre-May 25 transactions, such as financial information, even after that original purpose has passed, you can do so but you must delete or permanently “anonymize” the personal data attached to the transaction.

Of course, there are practical considerations. It is likely that 100 percent compliance with the consent requirement by U.S. companies with no physical presence in the EU prior to May 25, 2018 is going to be the exception, not the rule. As a result, good faith efforts by a U.S. company to satisfy the GDPR consent requirement by the deadline are likely to drastically reduce the risks of liability for non-egregious violations.

7. What else is in the GDPR besides the consent to retention of personal data issue?

Unfortunately, there is quite a bit more. The GDPR establishes many new rights for EU Individuals with respect to their personal data that do not apply to U.S. residents. For example, EU Individuals have the right to require you to erase all their personal data even after they have given their consent. This is known as the “right to be forgotten.” They also have the right to access their personal data and to require you to correct erroneous data. You are also required to “port” their personal data to other companies upon their request. There are specific data breach reporting requirements that supplement, but do not replace, the reporting requirements of U.S. state laws. Finally, there is a requirement that companies create their information databases on a “privacy by design” basis, minimizing the amount of personal data retained and otherwise facilitating the other rights of EU Individuals created by the GDPR.

8. Does the GDPR give extra time for these additional requirements?

No, but the likelihood of being called to task on those other requirements is much less than the risks from retaining personal data of EU Individuals after May 25 without GDPR-valid consent. The likelihood is that, because so many U.S. companies deal with EU Individuals, these additional requirements will eventually become the de facto standards in the U.S. too. As a practical matter, it may be too difficult for most companies to have different privacy protections for EU Individuals and non-EU Individuals.

9. What are the “multimillion dollar penalties” for violating the GDPR?

The maximum administrative fine that can be imposed by an EU member state’s supervisory authority on a “controller” or a “processor” of personal data for violations of the GDPR is the greater of 4 percent of annual global sales or €20 million. There is a tiered approach to the fines, with some less willful and less egregious offenses carrying a maximum fine of 2 percent of sales or €10 million. In some cases, aggrieved EU Individuals can seek remedial or compensatory payments from controllers or processors for violations of the GDPR.

10. It doesn’t seem right that the EU can impose all these requirements on U.S. companies that aren’t even present in their countries. Is it really enforceable?

There may be bona fide legal questions as to whether the EU actually has the legal authority to impose GDPR requirements on U.S. businesses that have no physical presence in the EU or EEA. It is therefore possible that, before or after May 25, one or more U.S. companies will seek a declaratory judgment in a U.S. court to the effect that some of the GDPR’s purported applications to U.S. companies are invalid.

¹The European Economic Area (the “EEA”) is comprised of the EU countries plus Iceland, Liechtenstein and Norway. The United Kingdom is still in the EU for this purpose.

Three recent air quality developments of particular note involve (1) important new guidance in Colorado for oil and gas operators of storage tanks, (2) the proposed revision of the Environmental Protection Agency’s (“EPA”) Audit Policy to provide auditing incentives and an agreement template for new owners of oil and gas facilities, and (3) a recent federal Clean Air Act (“CAA”) consent decree addressing emissions from midstream gas gathering activities involving pipeline pigging. Each of these developments is addressed more specifically below, with links to relevant documents.

Colorado Oil Storage Tank Guidance

On May 4, 2018, the Colorado Air Pollution Control Division finalized and published the Storage Tank and Vapor Control Systems Guidelines (“Guidelines”). The Guidelines are the result of a multi-year joint effort between the Division and the oil and gas industry and describe the technical and practical considerations for design, operation, and maintenance of vapor controls systems in Colorado. Specifically, the Guidelines aim to provide oil and gas operators regulatory certainty for compliance with Colorado’s air emission regulations, particularly, the “minimize leakage” and “operate without venting” standards in Regulation No. 7.

The Guidelines encompass two topics: (1) facility design and (2) operation and maintenance. The facility design procedures provide guidance to conduct an engineering and design analysis to ensure that vapor control systems have sufficient capacity to properly manage storage tank emissions. The operating and maintenance guidelines detail both preventative maintenance procedures and operational practices, including inspections and predictive analyses.

It is important to note that the Guidelines are, as the Division states, recommendations. The Guidelines do not create strict standards or practices for operators to follow. However, importantly, the Guidelines state that “the division expects in most instances where emissions from storage tanks are observed, a showing by the owner or operator that it has followed these guidelines will be sufficient to establish the observed emissions do not constitute a violation of the ‘operate without venting’ and ‘minimize leakage’ requirements of Regulation Number 7.”

As noted in the Guidelines, Davis Graham attorneys were significantly involved in the development of these Guidelines and can provide clients with valuable legal assistance regarding compliance going forward.

New Owner Audit Policy Revisions for Oil & Gas Facilities Proposed

The EPA is developing a New Owner Clean Air Act Audit Program specific to the oil and gas industry in the hopes of streamlining disclosures of non-compliance by new owners of oil and gas assets. See New Owner Clean Air Act Audit Program for Oil and Natural Gas Exploration and Production Facilities: New Owner Audit Program. The program will initially be made available to upstream exploration and production sites where the EPA alleges it has seen “significant noncompliance.” Related to this, the EPA recently released a standard audit program agreement template. It is unclear at this time whether the EPA envisions that the newly released agreement template will merely supplement the EPA’s existing New Owner Audit Policy and Corporate Audit Agreement, or whether this template agreement will be the exclusive mechanism for oil and gas operators to disclose to potential violations to the EPA related to new acquisitions. It is also unclear if the provisions in the released agreement template are negotiable, and if so, to what extent.

One particularly notable feature of the standard audit program agreement template is the provision that apparently requires companies to assess storage tank battery vapor control system engineering and design under the requirements outlined in Appendix B of the template. Indeed, the EPA states that a “key program component” of the New Owner Clean Air Act Audit Program will require that companies “assess storage tank battery vapor control system design as part of the audit process.” The engineering and design requirements in Appendix B are very similar to the requirements identified in several recent consent decrees the EPA has entered with various operators in Colorado and North Dakota related to these issues. Inclusion of these requirements in this new program suggests that the EPA, to some extent, believes these requirements apply nationwide and expects companies to be assessing engineering and design compliance when purchasing new facilities, regardless of the jurisdiction.

The EPA is currently seeking feedback from states, tribes, the regulated community, environmental NGOs, and other stakeholders about the template. The EPA will accept comments on the draft standard audit program agreement until Monday, June 4, 2018.

Gathering Line Maintenance Settlement

Another recent development of note is the settlement of alleged Clean Air Act violations by MarkWest Liberty Midstream and Resources, LLC and Ohio Gathering Company, LLC (“MarkWest”) in a consent decree with the U.S. Department of Justice, U.S. EPA, and Pennsylvania Department of Environmental Protection. This decree is unique in its focus on gas gathering pipelines and their maintenance through line “pigging.” Line pigging operations involve the insertion of a “pig” that travels through the line under pressure from the gas being gathered. As the pig travels through the pipeline, residual and pooled liquids and scale are pushed through the line ahead of the advancing pig. Pigs are routinely inserted and removed from various pipelines through use of pig launcher and receiver chambers that are constructed for this purpose when the pipeline is first installed.

In the consent decree lodged April 24, 2018, MarkWest agreed to significantly reduce emissions associated with its gathering line maintenance through use of jumper lines to drop pressures in pig receivers and launchers before opening them; to use proprietary “pig ramps” in existing and modified receivers and launchers to reduce liquid buildup and associated flashing losses when opening them, and to use combustors to reduce emissions at certain locations to below permitting thresholds, among other terms and conditions. The settlement also requires payment of $610,000 in civil penalties, and the supplemental environmental project provisions are valued at approximately $2.4 million. Emission reductions associated with the settlement are estimated at 706 tons per year of VOCs, including a drop of 84.7% in pigging-related emissions. The proposed consent decree is open to public comment for 30 days following publication in the Federal Register, and may be downloaded here.

The Environmental Group of Davis Graham & Stubbs LLP handles air quality regulatory, transactional, and litigation matters for its clients in the oil & gas and other industry sectors. Please contact John Jacus, Randy Dann, Shalyn Kettering, Will Marshall, or your Davis Graham attorney if you would like to discuss these three developments further, or other air quality matters of concern to your company.

Alleging public and private nuisance, trespass, unjust enrichment, and violations of the Colorado Consumer Protection Act, on April 17, 2018 Boulder County, San Miguel County, and the City of Boulder filed a nuisance lawsuit in Colorado State Court for Boulder County against Suncor and ExxonMobil. The lawsuit demands that the companies pay their alleged respective shares of plaintiffs’ claimed costs associated with climate change impacts, which the plaintiffs assert are caused by the use of fossil fuel products that were produced, promoted, and sold by defendants. The plaintiffs allege that the companies have known about the danger of their products for the climate for 50 years. The plaintiffs argue that fossil fuel products extracted and sold by the companies contribute to climate change.

This lawsuit is the latest in a string of climate change nuisance lawsuits brought by multiple cities and counties in California and New York. The Boulder lawsuit, however, is the first lawsuit brought in the U.S. interior, where sea level rise is not an issue. The Boulder lawsuit alleges damages related to changes in precipitation, dwindling snow pack, and more damaging fires.

Damages Sought in the Boulder Lawsuit

The plaintiffs seek compensation for past and future damages and costs to analyze, evaluate, mitigate, abate, and/or remediate the impacts of climate change, specifically, costs of the following:

• analyzing and evaluating the future impacts of climate alteration, the response to such impacts and the costs of mitigating, adapting to, or remediating those impacts;
• wildfire response, management, and mitigation;
• responding to, managing, and repairing damage from pine beetle and other pest infestations;
• increased drought conditions including alternate planting and increased landscape maintenance;
• additional medical treatment and hospital visits necessitated by extreme heat events, increased allergen exposure, and exposure to vector-borne disease, as well as mitigation measures and public education programs to reduce the occurrence of such health impacts;
• repairing and replacing existing flood control and drainage measures, and repairing flood damage;
• repair, maintenance, mitigation, and rebuilding and replacement of road systems to respond to the impacts of climate alteration;
• alteration and repair of bridge structures to retain safety due to increases in stream flow rates;
• repairing of physical damage to buildings owned by the plaintiffs;
• analyzing alternative building design and construction and costs to implement such alternative design and construction;
• loss of income from property owned by the plaintiffs due to reduced agricultural productivity or lease or rental income while property is unusable;
• public education programs concerning responses to climate alteration; and
• reduced employee productivity.

In addition, the Boulder plaintiffs seek compensatory damages for past and future damages, including but not limited to decreased value in water rights; decreased value in agricultural holdings and real property; increased administrative and staffing costs; monitoring costs; costs of past mitigation efforts; and all other costs and harms described in their Complaint. The plaintiffs also seek remediation and/or abatement of the hazards discussed above by the defendants “by any other practical means.”

The Boulder plaintiffs specifically disclaim seeking to enjoin any oil or gas operations or sales, or to force emissions controls, or for any damages for injuries to federal lands or for any of the defendants’ lobbying activities. The plaintiffs request a jury trial.

Likelihood of Success and Relationship to Other Recent Climate Change Lawsuits

As with the other climate change lawsuits, Boulder’s case will likely turn on two principle questions: (1) whether the alleged climate change impacts definitively be can traced to particular companies (in this instance ExxonMobil and Suncor); and (2) whether it can be proven that ExxonMobil and Suncor knowingly marketed their products despite actual knowledge of the harm the products could cause.

Previous efforts have failed because of the challenges of proof of causation between alleged events or harm and the actions of particular companies. The most notable recent case was the 2009 dismissal of the Alaskan village of Kivalina’s lawsuit against fossil fuel companies for their alleged role in sea level rise. Native Village of Kivalina, and City of Kivalina vs. ExxonMobil Corporation, et al. The Kivalina court found that there is no common law nuisance tort of global warming, that regulating greenhouse emissions was a political issue that needed to be resolved by Congress and the Administration rather than by courts, and found a lack of evidence linking sea level rise to the actions of particular fossil fuel companies. Because greenhouse gas emissions are created by almost everyone — from companies extracting oil to people driving cars — it is impossible, the court claimed, to pin the consequences of climate change on a single, or handful, of particularly bad actors.

The other previous lawsuit on the topic was the 2011 U.S. Supreme Court decision in American Electric Power v. Connecticut rejecting similar nuisance claims brought against companies for burning fossil fuels. The high court found that these lawsuits based on federal common law were improperly in federal court because greenhouse gas emissions were already regulated by an existing federal law: the Clean Air Act.

Climate change science has evolved significantly in the years since the Kivalina lawsuit, and scientists now claim to be able to attribute specific events to global warming. See “Researchers can now blame warming for individual disasters.” Additionally, environmental NGOs are developing arguments and reports alleging that 100 companies are responsible for 70 percent of the world’s greenhouse gas emissions since 1988. See Carbon Majors Report 2017.

The success of the recent such lawsuits is far from certain, but the costs of defending such cases could be high. The damages sought are extremely high. The Boulder plaintiffs speculate that the damages are measured in hundreds of millions of dollars. See “Here’s what Exxon Mobil, Suncor think of Colorado communities’ climate-change lawsuit.” The other lawsuits combined ask for damages in the billions.

What Happens Next

The defendants in the Boulder lawsuit are likely to remove the lawsuit to federal court, similarly to the defendants in lawsuits brought by Oakland and San Francisco against ExxonMobil and other majors. After removal, Oakland and San Francisco moved to remand the state public nuisance claims back to state court. On February 27, 2018 the Northern District of California in California v. BP P.L.C., et al, denied the motion to remand and found that the plaintiffs’ nuisance claims are governed by federal common law.

In California v. BP, the plaintiffs assert nuisance claims against the defendants under common law, seeking an abatement fund to help pay for sea walls and other climate-related defense infrastructure. Distinguishing AEP v. Connecticut, the California federal district found that the AEP ruling may not apply to plaintiffs’ claims, because the Clean Air Act only regulates the companies that burn fossil-fuels, not the companies that sell them. This assertion was in the context of procedural decision (finding that a remand to state court was not appropriate) not on the merits of preemption, but has been hailed as potentially indicating the court believes these types of nuisance claims are not preempted by the Clean Air Act. If that indication proves true and is upheld on appeal (all big ifs), coal, oil, and natural gas producers could face federal common law nuisance claims nationwide, rivalling the tobacco and asbestos litigation of the 1990s and early 2000s.

The Impact of Tax Reform on Private Equity and M&A

On December 22, 2017, the tax reform bill commonly known as the Tax Cuts and Jobs Act (the “Act”), was signed into law by President Trump. The Act is the most sweeping tax reform legislation in over 30 years and will have significant impacts on the private equity industry and on M&A activity in general.

On the domestic front, the headline reforms are a reduction in the corporate tax rate from 35% to 21% and a new deduction for non-corporate owners of pass-through entities (such as partnerships, LLCs taxed as partnerships and S corporations) and sole proprietorships that effectively lowers the tax rate on certain owners of such businesses. The Act also contains several revenue raisers that will impact private equity and M&A, including modifications to the taxation of carried interests and limitations on the deductibility of interest and net operating losses (NOLs).

The following is a high-level summary of important features of the Act that will affect private equity and M&A transactions in 2018 and beyond.

Corporate Rate Reduction – 21% Flat Rate

Effective for tax years beginning after December 31, 2017, the Act reduces the corporate tax rate from a top graduated rate of 35% to a flat rate of 21%. The Act also repeals the corporate alternative minimum tax.

The reduced corporate tax rate should impact the valuation of corporate targets for future deals and possible purchase price adjustments for currently pending transactions. In addition, this change should reduce the tax impact of an asset sale by a C corporation and, correspondingly, it also reduces the value of stepped-up asset basis for a corporate buyer (at least after the expiration of the temporary 100% bonus depreciation provision discussed below). As a result, the reduced corporate tax rate will change the calculus of whether a potential acquisition should be structured as a stock or asset acquisition.

The 21% corporate rate, when combined with the top qualified dividend rate of 23.8% for individuals, results in an effective tax rate of 39.8% on corporate earnings distributed to individual shareholders (this effective tax rate was previously about 50.5%). This is now comparable to the highest individual tax rate of 37% (plus the 3.8% Medicare or Net Investment Income tax, if applicable), which was reduced from 39.6% under the Act. As a result, the use of a C corporation and the resulting double taxation of earnings that are distributed to shareholders does not have the same impact as in the past (particularly when the new 20% deduction for qualified business income discussed below is unavailable).

The new attractiveness of C corporations will be further increased for new or existing companies that can qualify as a “qualified small business” under the Section 1202 rules, which remain unchanged by the Act. These rules provide for a 100% exclusion on the gain from the sale of stock of certain C corporations (up to the greater of $10 million or 10 times the basis in such stock) that was acquired at original issuance and held for at least five years.

As a result of the lower corporate tax rate, we believe there will be some increase in the use of C corporations for new ventures where a pass-through entity was historically the preferred option, as well as some conversions of existing pass-through entities into C corporations. There are many factors that influence the choice of entity that should be used in any particular business structure, but the more likely a business is to generate operating profits that will be reinvested in the business (rather than distributed to the owners), the more attractive a C corporation might become due to the lower 21% tax rate, the benefits of deferral on the second level of taxation at the shareholder level, the reduced tax filing obligations for shareholders, and the potential of excluding gain on the sale of qualified small business stock.

20% Deduction for Qualified Business Income

The Act provides for a 20% deduction for a non-corporate taxpayer’s allocable share of qualified business income (QBI) from partnerships, LLCs taxed as partnerships, and S corporations. In addition, although the deduction is commonly referred to as a “pass-through” deduction, it also applies to QBI from a sole proprietorship that is not operated through an entity.

QBI is generally taxable income with respect to a trade or business within the U.S., but excludes passive income (generally capital gains, dividends, and interest). Amounts paid for employee-type services to a business, such as a guaranteed payment from a partnership in exchange for services or amounts paid by an S corporation that are treated as reasonable compensation, are excluded. This will likely lead to increased scrutiny by the IRS over what constitutes reasonable compensation to S corporation shareholders and the characterization of partnership profits earned by service partners.

There are several limitations on the deductibility of QBI, and they are applied separately to each qualified trade or business. The deduction is capped at the greater of (i) 50% of the individual’s share of the W-2 wages paid by the business to employees and (ii) 25% of such W-2 wages plus the individual’s allocable share of 2.5% of the unadjusted cost basis of the business’s “qualified property” (generally depreciable assets used in the business).

Because of the limitations on QBI being keyed to wages paid by the qualified trade or business (or wages paid plus capital invested), careful consideration will be needed in designing the organizational structure of a business to ensure that wages paid to employees are appropriately credited to the qualified trade or business. For example, many partnerships that issue equity to employees have setup employment companies as separate entities to avoid certain self-employment issues for those employees. These structures may need to be reexamined to ensure that wages paid by the employment company count towards the pass-through deduction limitation. In addition, this limitation creates an incentive to treat service providers as employees rather than as independent contractors.

The pass-through deduction is generally not allowed for income from a “specified service trade or business,” which includes (but is not limited to) service businesses in health, law, accounting, consulting, and financial services, unless an individual’s taxable income is below a certain threshold. The specified service trade or business exclusion phases in for a taxpayer with taxable income in excess of the applicable threshold amount, currently $315,000 plus $100,00 for joint filers, and $157,500 plus $50,000 for other taxpayers. The exclusion for service related businesses means that management fees received by an investment manager of a private equity fund would not be QBI, but pass-through income earned by the fund from its non-corporate portfolio companies could qualify as QBI.

The pass-through deduction applies at the individual partner or shareholder level. Existing tax distribution provisions in partnership agreements and LLC operating agreements, therefore, generally will not account for the deduction. Accordingly, such provisions should be amended if the relevant parties want to account for the deduction in calculating tax distributions.

For taxpayers that are in the top individual income tax bracket of 37% and also able to take advantage of the full 20% deduction for QBI, this will result in an effective top marginal rate of 29.6% (plus the 3.8% Medicare or Net Investment Income tax, if applicable). This effective rate remains appreciably lower than the 39.8% effective rate applicable to income of a C corporation distributed to individual shareholders.

Although, as mentioned above, we believe the reduced corporate tax rate will likely result in at least some increase in the use of C corporations, we believe the majority of portfolio companies will continue to operate as pass-throughs. The traditional benefits of pass-through entities (e.g., flowing losses through to owners, a single-layer of tax, and the ability to give a buyer the benefit of a basis step-up in the company’s assets), coupled with the new pass-through deduction, will likely outweigh the benefits provided by the lower corporate tax rate. In addition, if corporate tax rates are raised in the future, the costs of converting from a corporation to a pass-through could be prohibitive, while if the opposite were to occur, a pass-through entity generally can convert to a C corporation in a nontaxable transaction.

Limitations on Carried Interest

The Act extends the holding period from 1-year to 3-years for assets held by an investment fund before service providers holding carried interests in the fund can recognize long-term gains on the sale of such assets. The extended holding period only applies to “applicable partnership interests” that are received in connection with the performance of substantial services in a trade or business that consist of (i) raising or returning capital, and (ii) either investing in (or disposing of) certain investment assets or developing such assets. This definition of “applicable partnership interests” should capture virtually all carried interests issued to principals of an investment fund. The provision applies to interests issued prior to the effective date of the Act (i.e., no grandfathering).

The extended holding period may have limited effect on most private equity investments, as there is typically an investment horizon beyond 3 years, but this obviously creates concern in cases where there is a potential for a quick flip. In addition, funds should monitor add-on investments made by their portfolio companies to ensure, to the extent possible, that they do not lose the benefit of a historic holding period with respect to such investments. Depending on how such investments are structured, they could result in a bifurcated (or new) holding period that would implicate the application of this rule.

This new rule does not apply to partnership interests held by a person employed by a company (other than the issuing partnership) that is engaged in an “applicable” trade or business (i.e., not an investment management-type business) if such person provides services only for that company. We therefore believe that most profits interests issued to executives and employees of a portfolio company should not be subject to the new holding period requirement.

While the increased holding period requirement applies to the traditional carried interests in a private equity fund, it should be noted that it does not apply to the interests held by the sponsor that directly relate to cash investments in the fund and only provide returns commensurate with other capital contributed. This exception should apply to basic capital interests, but it will likely not apply to “catch-up” type interests embedded in a capital interest.

Probably the most interesting aspect of this new rule is that it creates a new environment where the long-term holding period for fund sponsors is different than that of investors. Sponsors and investors will need to carefully address this potential conflict when structuring future investments.

Full Expensing of the Cost of New or Used Qualified Property

The Act provides for 100% bonus depreciation for qualified property placed in service between September 27, 2017 and January 1, 2023. Qualified property generally includes most tangible property (other than buildings and some building improvements) and computer software. The 100% bonus depreciation rate is scheduled to be phased down for property placed in service starting in 2023 with a 0% rate applying in 2027 and thereafter.

Previously, bonus depreciation was 50% and only applied to new property placed in service for the first time. Expanding bonus depreciation to 100% provides full expensing for new equipment purchases for businesses, providing a substantial incentive for capital investments. However, including used property should have even larger implications for M&A transactions, as structuring a transaction as an asset acquisition (or as a deemed asset acquisition such as a stock acquisition with a Section 338(h)(10) election) now provides an immediate deduction to the buyer for any purchase price allocable to equipment or other qualified property. Accordingly, when looking at a potential acquisition or sale of an operating business with significant tangible property, there will be a substantial advantage from the buyer’s perspective to structure as an asset sale (or deemed asset sale) and an increased importance will be placed on the allocation of the purchase price among the assets of the business.

While nothing is certain when it comes to planned phase outs, as there is often political pressure to extend taxpayer favorable provisions as sunset provisions get closer, private equity funds should consider these planned phaseouts in long-term strategic planning, as valuations for portfolio companies could change for a potential buyer if full expensing is not available.

NOL Limitations

The Act will have a significant impact on the role of NOLs in M&A transactions. The reduced 21% tax rate applicable to corporations will reduce the value of NOLs to potential buyers. In addition, under the Act, NOLs can no longer be carried back to prior years, but can be carried forward indefinitely (previously, NOLs could be carried back two years and carried forward 20 years). NOLs created after 2017 can only be used to offset a maximum of 80% of a taxpayer’s taxable income.

A target corporation will often incur substantial transaction-related expenses that generate an NOL for the target corporation’s year that ends (or is deemed to end) on the closing date. Previously, this NOL could be carried back to receive refunds of prior year income taxes, and selling shareholders frequently would be compensated for the tax benefit arising from the NOL generated by these transaction-related deductions (either through an increase in the purchase price paid at closing or through post-closing payments as the tax benefits are realized by the buyer). Now that such an NOL cannot be carried back to obtain an immediate tax benefit and can only be carried forward, the value of such NOL will be limited by the application of both the new 80% limitation as well the Section 382 limitation, which remains intact under the Act. These changes will affect negotiations regarding whether, and how, sellers get compensated for tax benefits arising from transaction-related expenses.

Limitation on Interest Deductions

Under the Act, taxpayers can deduct business interest expenses only up to 30% of adjusted taxable income (ATI). ATI is generally defined in a manner equivalent to earnings before interest, taxes, depreciation and amortization (EBITDA) until 2022, but after 2022 will not include deductions for depreciation, amortization, or depletion (EBIT). These new rules will not apply to certain small businesses with average gross receipts of under $25 million. Disallowed interest deductions can be carried forward indefinitely

These new limitations on the deductibility of interest will impact the ability to highly lever a portfolio company and could result in the use of more preferred equity in place of subordinated debt. In addition, given the lack of grandfathering of outstanding debt, companies that are potentially subject to these limitations should assess whether they should adjust their capital structure.

Summary

While the Act provides many taxpayer benefits that are likely to encourage private equity and M&A activity, there are also several areas where more restrictive rules are being applied. Although many of the historic strategies and structures for private equity and M&A will continue to be utilized, we believe the Act will provide opportunities to improve on these past structures and to create new ones. As the Act is modified and clarified by future technical corrections and guidance from the Treasury Department and the IRS, Davis Graham will continue to monitor and provide updates on key developments.

For more information on the Act and its potential impact on existing organizational and transaction structures, please contact the authors of this alert.

July 28, 2017 marked a significant victory for Davis Graham & Stubbs LLP attorneys Tom Johnson and Jennifer Allen in a 14-year lawsuit. The two defeated class certification on behalf of their client Farmers Insurance. The case began in 2003, when plaintiffs’ attorneys filed a large class action against all major auto insurance carriers in Colorado. The plaintiffs argued that they were fraudulently induced into purchasing more uninsured/underinsured motorist coverage because the insurance companies did not inform customers of a 2001 Colorado Supreme Court case that broadened the scope of uninsured/underinsured motorist coverage. The initial class eventually was separated into over 50 class actions. The proposed class in the Farmers action included over 250,000 Colorado residents and involved over $65 million in potential damages.

Mr. Johnson and Ms. Allen, along with Janette Ferguson of Lewis Bess, participated in a week-long class certification evidentiary hearing in April. On July 28, the Court released its 27-page order denying class certification, finding that Farmers did not intentionally conceal information from its customers and that many customers would have continued to purchase the insurance even if told of the Supreme Court decision.