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.

The Colorado Division of Securities has adopted new rules applicable to investment advisers effective as of July 15, 2017.^[1] The adopted rules include an exemption from state licensing requirements for certain investment advisers. Specifically, the new Rule 51-4.11(IA) (the “New Rule”) under the Colorado Securities Act (the “Act”) exempts certain “private fund advisers” from the Act’s licensing requirements.^[2] The effect of the New Rule is that certain investment advisers who are subject to the Act and who fall below the dollar amount of assets under management for registration with the SEC,^[3] now may also be exempt from registration with the state of Colorado, subject to the terms of the New Rule.

Eligibility and Requirements for the Licensing Exemption

Under the New Rule, a private fund adviser, which is an “investment adviser” under the Act who provides investment advice solely to one or more “qualifying private funds,” is exempt from the licensing requirements of Section 11-51-401(1.5) of the Act, subject to certain additional requirements under the New Rule. A “qualifying private fund” means a private fund that meets the definition of a “qualifying private fund” in Rule 203(m)-1 under the federal Investment Advisers Act of 1940 (the “Advisers Act”), which is generally 3(c)(1) and 3(c)(7) funds.^[4]

To qualify for the exemption under the New Rule, an investment adviser must satisfy each of the following conditions:

1. The investment adviser must provide investment advice only to “qualifying private funds”;
2. Neither the investment adviser nor any of its advisory affiliates may be subject to a bad actor disqualification in Rule 506(d)(1) under the federal Securities Act of 1933 (the “Securities Act”);
3. The investment adviser must file as an “exempt reporting adviser” on Form ADV with the state of Colorado, generally through the Investment Advisory Registration Depository (“IARD”); and
4. The investment adviser must pay the fees prescribed by the Colorado securities commissioner.

In addition to the above requirements, if the investment adviser provides investment advice to at least one qualifying private fund that is a 3(c)(1) fund (and that is not a “venture capital fund”^[5]), then the following additional requirements apply for such investment adviser to qualify for the licensing exemption:

1. Any such 3(c)(1) fund that is not a venture capital fund must be beneficially owned exclusively by persons who meet the definition of a “qualified client” under Advisers Act Rule 205-3^[6] at the time of investment in the fund;
2. The investment adviser to such 3(c)(1) fund that is not a venture capital fund must make certain disclosures to all investors including the disclosure of (i) all services, if any to be provided to investors, (ii) all duties, if any, the investment adviser owes to investors, and (iii) any other material information affecting the rights and responsibilities of the investors; and
3. The investment adviser must obtain, on an annual basis, audited financial statements of each such 3(c)(1) fund that is not a venture capital fund, and deliver a copy of such audited financial statements to each beneficial owner of the fund.

Considerations for Using the New Exemption

Investment advisers with a place of business in Colorado or who are otherwise subject to the Act should consider the following in determining whether to take advantage of the licensing exemption under the New Rule:

1. The SEC rules for investment adviser registration still apply. If an investment adviser is required to register under the SEC rules and regulations, this exemption does not apply.
2. An investment adviser that provides investment advice to qualifying private funds that are 3(c)(1) funds and are not venture capital funds should carefully review the status of each of the fund’s investors, especially if the fund has accepted friends and family investors who might not satisfy the “qualified client” standard. However, the exemption does allow investment advisers with current non-qualified clients in 3(c)(1) funds that are not venture capital funds to be grandfathered under the exemption so long as: (i) the subject fund existed prior to July 15, 2017 (the “Effective Date”), (ii) as of the Effective Date, the subject fund ceases to accept investors who are not “qualified clients,” and (iii) the investment adviser provides all fund investors with the information required to be provided to 3(c)(1) fund investors under the New Rule, including annual audited financial statements.
3. Investment advisers relying on this licensing exemption will still be required to file an abbreviated version of Form ADV – also known as an “exempt reporting adviser report” – which will continue to be publicly visible and which will contain certain information regarding the investment adviser’s business operations and ownership structure.
4. The licensing exemption only applies to investment advisers who exclusively advise 3(c)(1) and 3(c)(7) funds. Investment advisers who advise funds that are not relying on one or both exclusions under the 1940 Act^[7] will not qualify for this exemption.
5. Per the instructions to Form ADV, all assets under management in a 3(c)(1) or 3(c)(7) fund will count towards the $100 million in assets under management threshold for eligibility to register as an investment adviser with the SEC. Additionally, if the assets under management in such a fund or funds meet or exceed $150 million, an investment adviser may be required to register with the SEC under the federal rules and regulations.

Although the Colorado Division of Securities did not issue any formal written guidance with respect to the New Rule prior to the effective date, additional guidance may be forthcoming. Such guidance is likely to include, for example, instructions on whether investment advisers who are already licensed in Colorado or registered with the SEC will need to first file on Form ADV-W withdrawing their registrations before submitting an exempt reporting adviser report in reliance on the New Rule.

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^[1] New rules with respect to cyber security, business continuity planning, and other matters are also among the rules that went effective on July 15, 2017. See https://www.colorado.gov/pacific/dora/securities-law-rules for more details.

^[2] Under the previous rules, those private fund investment advisers with a place of business in Colorado or who were otherwise subject to the Act and who did not meet the eligibility requirements to register with the Securities and Exchange Commission (the “SEC”) were generally required to be licensed with the Colorado Division of Securities.

^[3] Generally speaking, in accordance with the Advisers Act and the instructions to Form ADV, advisers exclusively to private funds are required to register with the SEC when they have reached $150 million in assets under management and are eligible to register with the SEC when they have reached $100 million in assets under management.

^[4] A 3(c)(1) fund is a privately offered fund that has no more than 100 beneficial owners. Subject to certain exceptions, a 3(c)(7) fund is a privately offered fund whose beneficial owners all qualify as “qualified purchasers” under Section 2(a)(51) under the federal Investment Company Act of 1940 (the “1940 Act”).

^[5] A private fund that meets the definition of a “venture capital fund” under the federal Advisers Act Rule 203(I)-1.

^[6] Note that while all investors in a 3(c)(1) fund may be “accredited investors” as such term is defined under the Securities Act, not all accredited investors qualify as “qualified clients” under Rule 205-3 of the Advisers Act.

^[7] Such non-qualifying funds include private funds that are excluded from the definition of “investment company” under Section 3(c)(5) or Section 3(c)(9) of the 1940 Act. However, a fund that qualifies for one of these exclusions but also meets the requirements for Section 3(c)(1) or Section 3(c)(7) could be included in the definition of “qualifying private fund.”

On June 6, 2017, Governor Hickenlooper signed Colorado House Bill 17-1200 into law, amending the Colorado Public Benefit Corporations Act (C.R.S. § 7-101-501 et seq.) (the Act). The key amendments are:

Name Requirement Removed

The Act no longer requires a public benefit corporation (PBC) to include “PBC,” “P.B.C.” or “public benefit corporation” in its legal name. However, a PBC that opts not to do so must, for all future stock issuances, provide notice of its PBC status to the acquirers of that stock.

Limited Cooperative Associations Eligible for PBC Status

The Act clarifies that a limited cooperative association formed under C.R.S. § 7-58-101 et seq. may take the form of a PBC, and that the voting requirements described in C.R.S. §§ 7-101-504(1) and (4) relating to certain amendments, mergers, and dissenter’s rights apply to the equity holders of PBCs that are cooperative entities in the same way they apply to stockholders of PBCs that are corporations.

List of Fundamental Transactions Subject to 2/3 Vote Broadened

The Act expands the list of corporate transactions requiring a two thirds vote of each class of stock outstanding (including classes of non-voting stock) to include virtually any transaction that results in (a) a sale or other disposal of all or substantially all of the PBC’s stock or assets, (b) a conversion or reorganization, or (c) any diminution or alteration of the public benefit purpose or purposes stated in the PBC’s articles of incorporation.

The amendments also:

– Clarify the PBC’s annual report requirements with respect to the third party standard used in such reports.

– Clarify that the Act is limited to PBCs and is not intended to, and does not, affect how the Colorado corporate laws applicable to non-PBC corporations (or any other corporate entity) should be applied under Colorado law.

For more information on these changes or the Act generally, please contact the authors of this Alert.

On May 2, 2017, the Colorado Oil and Gas Conservation Commission (“COGCC”) issued a Notice to Operators (“NTO”) regarding the inspection, identification, and abandonment of certain flowlines and pipelines. By its terms, the NTO goes beyond existing COGCC Rules to require operators to inspect and report on all flowlines and pipelines within 1,000 feet of a building unit and if a line is active to confirm its integrity. Operators also must ensure that all flowlines and pipelines are properly abandoned regardless of building unit proximity. Prompt action is required, with 30 and 60 day deadlines imposed. The COGCC issued the NTO at the direction of Governor John Hickenlooper who called for a statewide review of existing oil and gas operations in response to a home explosion that killed two persons and critically injured another.

The NTO creates a two-phase process to systematically inspect, inventory and abandon certain flowlines and pipelines. Operators must complete Phase 1 by May 30, 2017 and Phase 2 by June 30, 2017.

Phase 1 – Inspection and Inventory

Phase 1 of the NTO requires that operators inspect all existing flowlines and pipelines located within 1,000 feet of a building unit (residence or commercial facility). Flowlines, as used in the NTO, are broadly defined as “any conduit for gas, oil, condensate, or other liquid or gaseous hydrocarbons” that meet the regulatory definition of flowlines. The NTO notes that flowlines may be known by different names, such as a “well site flowline, return line, sales line, dump line, process piping, fuel gas supply line, and non-well site flowline.”

The operator must also provide the COGCC with inventory and location data for all such flowlines and pipelines, including the API and location ID numbers of any associated well or tank battery, the GPS location for each endpoint of any flowline, and its current status (active or scheduled for abandonment). Regardless of the distance to a building unit, operators are required to inspect and verify that any existing flowline or pipeline not in use is abandoned pursuant to Rule 1103 and that it is clearly marked and capped and all operating valves are removed until it is abandoned.

Phase 2 – Integrity Verification and Abandonment

Phase 2 of the NTO requires operators to verify and document that all flowlines within 1,000 feet of a building unit have integrity. The exemption from pressure testing requirements under Rule 1101.e.(2) for low pressure flowlines (less than 15 psig) does not apply and all flowlines must be tested regardless of operating pressure. An operator may satisfy this requirement if it has a documented integrity test completed after November 1, 2016. Phase 2 of the NTO also requires operators to complete the process of abandoning all flowlines or pipelines not actively operated, regardless of distance to a building unit. An operator must use signage, lock-out/tag-out procedures, and fencing to avoid unintentional reactivation when a flowline or pipeline is undergoing abandonment pursuant to Rules 604.c.(2)M. and 605.c.(3).

The NTO provides several acceptable methods of abandonment. The COGCC’s recommended practice for flowlines and pipelines within 1,000 feet of a building unit is removal of the entire line. Alternatively, an operator may fill the abandoned pipe with backfill material such as sand or controlled density fill (cement). These methods are in addition to Rule 1103, which requires the operator to disconnect the line from the wellhead, tanks and other sources, purge the line, and cut off and permanently seal the line below ground. Once complete the operator must notify the COGCC and local government of the abandonment.

If an operator desires to change the status of an inactive flowline or pipeline to active, it must do so prior to June 30, 2017. The operator must also provide the COGCC with the line’s associated well API number and tank battery location ID number, GPS location information, and regardless of the operating pressure perform a pressure test as otherwise required by Rule 1101.e.(1).

The Notice to Operators is available here.

Questions

The NTO raises several questions for operators, which will likely be addressed through further clarification. One question concerns its scope, as it variously refers to “Flowlines,” to “Flowlines and pipelines,” and to “Flowlines or pipelines.” The pipeline references suggest that the NTO encompasses more than flowlines, but the COGCC has indicated that the NTO is limited to flowlines as defined in the 100 Series Rules. A similar issue is whether the NTO applies to flowlines that don’t convey hydrocarbons. Although the NTO defines flowlines as lines that transport “liquid or gaseous hydrocarbons,” the COGCC has indicated that the NTO applies to all flowlines including those that transport water.

Another question involves differences between the NTO and existing COGCC regulations. For example, Rule 1101.e.(2), exempts low pressure flowlines from pressure testing requirements, but the NTO eliminates this exemption for the testing it requires. Similarly, the NTO requires that flowlines not in use be marked and abandoned, which exceed the current requirements under Rule 1103, and it authorizes abandonment using methods that are not mentioned in Rule 1103. These and other differences suggest that the COGCC may follow the NTO with rulemaking on this subject.

A third question contains the enforceability of the NTO. Although the NTO uses mandatory language, it is probably not legally enforceable because it appears to be a rule of general application and the COGCC did not comply with the Administrative Procedure Act in issuing it. Nevertheless, the oil and gas industry has already indicated that it will comply with the NTO due to the paramount importance of public safety as recognized by Governor Hickenlooper in his accompanying directive.

Directing a Response to the NTO

As with any administrative directive, the NTO requires action be taken by operators in a very short period of time. It effectively requires the conduct of company-specific investigations and evaluations of “flowlines and pipelines” in proximity to occupied buildings. As with most regulatory compliance investigations, some care and thought is warranted in structuring such an effort so as to protect the company’s interests and preserve the privileged and confidential character of various communications made and documents created or possibly produced in response. This is primarily accomplished by involving in-house and outside legal counsel to direct the investigation and help prepare the response(s), and carefully controlling the scope of personnel involved in the effort within the respondent company. To the extent outside consultants and contractors are involved in the effort, it may also affect how and on what terms they are engaged, including possibly being engaged by outside counsel. Finally, the proprietary nature of Land Department information that is called for in response to the NTO may be the subject of a claim of business confidentiality under the Colorado Open Records Act, to protect it from public disclosure by the COGCC. Operators may wish to claim such status for portions of their responses to the NTO.

If you or your company have any questions regarding the NTO, please contact Dave Neslin, John Jacus, Randy Dann, or Greg Nibert.