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.

In In re Ferrer, 2017 CO 14, announced Monday, February 27, the Colorado Supreme Court recognized a new defense potentially available to employers in cases in which the employer is sued based on its employee’s negligence. In such cases, where the employer is willing to admit that the employee was acting within the scope of their employment—and thus that the employer will be responsible for paying a judgment against the employee—the Supreme Court held that any direct negligence claims against the employer should be dismissed.

Ferrer arose from a late-night accident in Lower Downtown, Denver, in which a taxicab driver struck two pedestrians, causing serious injuries. The plaintiff sued the cab driver for negligence and argued that the cab company, Yellow Cab, should be liable for the driver’s negligence under the doctrine of respondeat superior. The plaintiff also brought claims directly against Yellow Cab for its own alleged negligence in hiring, supervising, and training the driver, and in entrusting him with a vehicle.

Yellow Cab initially argued that the driver was an independent contractor, and thus Yellow Cab could not be liable for the damages caused by the driver’s negligence. In an amended answer, however, Yellow Cab changed course and conceded that the driver was an employee, and was acting within the scope of his employment. This concession meant that, as a matter of law, Yellow Cab would be required to pay any judgment for the damages caused by the driver under the doctrine of respondeat superior.

However, Yellow Cab also pointed to a line of authority from outside Colorado, principally McHaffie v. Bunch, 891 S.W.2d 8212 (Mo. 1995), providing that, when an employer concedes that it is liable for any damages caused by its employee under the doctrine of respondeat superior, the plaintiff is barred from asserting claims directly against the employer that are based only on the employee’s actions. The trial court agreed, and dismissed the direct claims against Yellow Cab; the plaintiff sought immediate review in the Colorado Supreme Court under Appellate Rule 21.

In a 4-3 divided decision, the Court (Justice Marquez writing) agreed with Yellow Cab, holding that “where an employer has conceded it is subject to respondeat superior liability for its employee’s negligence, direct negligence claims against the employer become redundant and wasteful.” ¶ 26. Because “both vicarious liability and direct negligence claims are tethered to the employee’s tortious acts,” the Court held that allowing the direct claims would be a waste of judicial resources, while not increasing the possible recovery for the plaintiff. ¶¶ 30-31. The Court also noted that evidence relevant to the employer’s negligence—such as the employee’s prior driving record—would be unfairly prejudicial to the employee. ¶ 32.

Importantly, the Court held that its rule applies even where a plaintiff may have evidence that could support an award of exemplary damages against the employer: “Because any direct negligence claims against the employer are barred, there can be no freestanding claim against the employer on which to base exemplary damages.” ¶ 45. The Court held that the plaintiff in Ferrer had not produced sufficient evidence to support an award of exemplary damages, but even if she had, the direct negligence claims against Yellow Cab should still be dismissed. On this point, the Court went beyond courts in other states, which have held that, where punitive damages against the employer may be at issue, direct liability claims should not be dismissed. See, e.g., Plummer v. Henry, 171 S.E.2d 330 (N.C. Ct. App. 1969).

Justice Gabriel dissented, joined by Chief Justice Rice and Justice Hood. The dissent would have held that the plaintiff’s direct negligence claims against Yellow Cab were based on Yellow Cab’s conduct, not the derivative conduct of the driver, and thus should not be dismissed. The dissent was also troubled by the potential unfairness of Yellow Cab initially claiming that the driver was an independent contractor, but changing course to take advantage of the McHaffie rule.

In Ferrer, the Court adopted a potentially potent defense for employers sued for the negligence of their employees. While application of the rule requires that the employer admit respondeat superior liability—and thus that the employer ultimately pay any judgment against the employee—that admission brings with it the benefit of dismissal of the direct claims against the employer. This decision could therefore eliminate claims against employers for their conduct in hiring, retaining, and supervising the employee as well as narrow the scope of discovery, potentially putting the employer’s conduct in hiring, supervising, or training the employee off limits from discovery. Removing direct claims against the employer may also implicate insurance coverage, and could provide a quicker path to settlement. Employers should be aware of this defense and discuss its potential use with their attorneys at the earliest stage of litigation.

If you have any questions regarding this alert, please don’t hesitate to contact your Davis Graham attorney or the authors of this alert.

A recent Colorado Supreme Court case has clarified the statutory tolling provision concerning third-party construction defect claims. In Goodman v. Heritage Builders, Inc., 2017 CO 13, the Court held that such claims are timely—irrespective of the general construction defect statutes of limitations and repose—so long as they are asserted within the 90-day period set forth in 13-80-104(a)(b)(II), C.R.S.

Generally speaking, construction defect claims are subject to a two-year statute of limitations, 13-80-102, and a six-year statute of repose, which can extend up to an additional two years for claims arising during the fifth or sixth years after substantial completion. 13-80-104(1)(a). Third-party construction defect claims, however, are governed by section 13-80-104(1)(b)(II), which provides:

Notwithstanding the provisions of paragraph (a) of this subsection (1), all claims … by a claimant against a person who is or may be liable to the claimant for all or part of the claimant’s liability to a third person: (A) Arise at the time the third person’s claim against the claimant is settled or at the time final judgment is entered on the third person’s claim against the claimant, whichever comes first; and (B) Shall be brought within 90 days after the claims arise, and not thereafter.

Such third-party claims may be asserted during the principal construction defect litigation, or within the 90-day period following settlement or final judgment of such litigation. CLPF-Parkridge One, L.P. v. Harwell Investments, Inc., 105 P.3d 658, 665 (Colo. 2005).

In a series of cases, the Colorado Court of Appeals held that, while section 13-80-104(1)(b)(II) tolled the statute of limitations for construction defect claims by general contractors against subcontractors, it did not affect operation of the statute of repose. See Sierra Pac. Indus., Inc. v. Bradbury, 2016 COA 132; Shaw Const., LLC v. United Builder Servs., Inc., 2012 COA 24; Thermo Dev., Inc. v. Cent. Masonry Corp., 195 P.3d 1166 (Colo. App. 2008). In short, these cases held that a third-party construction defect claim asserted after the statute of repose period had run was barred regardless of whether the claim was asserted within the 90-day period provided by section 13-80-104(1)(b)(II). The Colorado Supreme Court disagreed.

In Goodman, the Court found that “the phrase ‘[n]otwithstanding the provisions of paragraph (a) of this subsection (1),’ plainly and unambiguously precludes the application of both the statute of limitations in section 13-80-102 and statute of repose in section 13-80-104(1)(a) to third-party claims made pursuant to section 13-80-104(1)(b)(II).” Accordingly, the Court overruled the previous Court of Appeals decisions and held that “the statute of repose is irrelevant for purposes of third-party claims brought under section 13-80-104(1)(b)(II).”

The Colorado Supreme Court’s decision in Goodman benefits general contractors by clarifying an ambiguity concerning when they must assert third-party claims against their subcontractors and suppliers and allowing such claims regardless of whether the statute of repose period expired. For subcontractors and suppliers, however, the decision provides a mixed bag. On one hand, subcontractors and suppliers cannot rely on the six- (up to eight)-year statute of repose as an absolute bar to claims against them. They may have to defend against claims first brought an undeterminable number of years after substantial completion if litigation involving the general contractor is drawn out. On the other hand, the decision may ultimately reduce the number of claims asserted against subcontractors and suppliers by removing the incentive for general contractors to prematurely file third-party claims rather than risk being barred by the statute of repose.

For more information on this or other issues concerning construction litigation, please contact the authors of this article or visit the Davis Graham website.

The Congressional Research Service (CRS) issued a report on January 24, 2017 analyzing how the 115^th Congress and new administration may impact key Obama-era Clean Air Act (CAA) rules. The report’s primary conclusion is that the courts, not Congress or the Environmental Protection Agency (EPA), will be the primary venue for challenges to these rules. Whether this proves true, the report’s secondary conclusion—that the CAA’s regulatory structure faces an “unusual degree of uncertainty in 2017”—may be more relevant. Many companies are struggling to discern how this sudden uncertainty may impact their businesses. This legal alert highlights some of the CAA rules addressed in the CRS report and discusses potential outcomes and implications for affected industries. Our attorneys are following these developments and are available to discuss their impacts on your business.

Oil and Gas Air Rules

EPA finalized updates and amendments to the 2012 New Source Performance Standards (NSPS) known as “Quad Oa” on June 3, 2016. Thus, Quad Oa is immune from repeal under the Congressional Review Act (CRA), which applies only to rules promulgated after June 13, 2016. Nonetheless, there are two remaining avenues to challenge Quad Oa—administrative and judicial. With respect to the latter, both the 2012 and 2016 NSPS rules are the subject of pending litigation before the D.C. Circuit (in full disclosure, Davis Graham represents a client in this challenge). The court granted an extension for the filing of briefing schedules and format until March 20, 2017 to allow the new administration to assess its litigation strategy. It is premature to speculate about the outcome of this litigation. If it does move forward, however, the case is unlikely to be fully briefed until later this spring with a decision unlikely before later in 2017.

This leaves administrative relief. The Trump EPA may attempt to revise the NSPS rules either through notice and comment rulemaking under the Administrative Procedure Act (APA) or through the unique “administrative reconsideration” mechanism under Section 307(d)(7)(B) of the CAA. The lengthy notice and comment rulemaking process would extend well beyond the 115^th Congress and likely prompt further litigation at its conclusion. This is the most obvious path, however, for effecting widespread, structural changes to the rules, such as addressing the nature and scope of EPA’s authority to issue NSPS standards for the oil and gas industry. Administrative reconsideration would likely take less time, but it poses its own challenges, including the fact the reconsideration process for the 2012 NSPS has already concluded leaving only Quad Oa subject to this option. Further, EPA is arguably more constrained in how it can change Quad Oa through administrative reconsideration—a process most often used to fix a rule’s technical implementation. Thus, looking forward, we are unlikely to see substantive changes to the oil and gas NSPS before late 2017. In the meantime, the rules are effective, and companies must comply.

The BLM venting and flaring rule poses a different set of uncertainties (in full disclosure, Davis Graham represents clients in this challenge as well). A federal court in Wyoming denied industry’s and the states’ motions for a preliminary injunction on January 16, 2017, and the rule took effect the following day. Although BLM phased in major portions of the rule (e.g., leak detection and repair and the flaring limits), other important portions of the rule (e.g., royalty provisions) are in effect. If the litigation proceeds, the case will be fully briefed by mid- to late-April, and a decision could come soon after. As with EPA in the NSPS litigation in the D.C. Circuit, it is possible that the Trump Administration’s BLM takes a different posture in the litigation. And it is similarly unclear how such a change would affect the litigation—especially given the numerous environmental groups party to the case.

The possible rescission through the CRA casts a long shadow over this rule, irrespective of the litigation. The venting and flaring rule has been discussed as one of the top priorities for CRA consideration. At the time of this legal alert, both chambers of Congress have introduced disapproval resolutions to repeal the rule, and the House of Representatives is likely to vote on its resolution later this week. While the timing of a Senate vote is less certain, it must occur within 60 legislative days of the start of the 115^th Congress. One wrinkle is that a rule successfully repealed through the CRA may not be reissued in “substantially the same form” except under authority of a newly enacted law. The definition of “substantially similar” has never been tested. This begs the question whether full rescission of the venting and flaring rule would allow BLM to adopt a more limited fix to venting and flaring rules (i.e., NTL-4A) absent authorization from a new law. Accordingly, repeal of the rule through the CRA is not without risk for the oil and gas industry.

Ozone Standard

The Trump Administration has also discussed repealing the 2015 ozone standard, which was finalized in October 2015. Doing so would require full APA notice and comment rulemaking, and the lengthy process would almost certainly culminate in litigation. The consequences of doing so could be drastic. For example, places like the Denver Metropolitan Area, North Front Range 8-hour ozone non-attainment area have been designated “moderate” non-attainment under the previous, less stringent 2008 standard (75 ppb). If the 2015 standard is repealed, Colorado’s Front Range and other areas could be bumped up to “serious” non-attainment status under the 2008 standard, causing significant new provisions of the CAA to kick in. This would include the major source threshold for volatile organic compounds (VOCs) and nitrogen oxides (NOx) moving from 100 tons per year (tpy) to 50 tpy. Should this occur, hundreds of additional facilities could fall into major source status, posing widespread economic burdens for area businesses, potentially slowing future development, and placing an extreme permitting burden on the state regulatory agency.

Adding to the complexity surrounding ozone are the two different standards–2008 and 2015. In its 2015 ozone standard implementation proposal, EPA offered two options for reconciliation: (1) retain the 2008 standard in all non-attainment areas until each area meets the 75 ppb standard; or (2) revoke the 2008 standard subject to anti-backsliding criteria, leaving only the 2015 standard in place. Each comes with its own set of pros and cons. The comment period for the 2015 ozone standard implementation proposal has been extended until February 13, 2017, and businesses and industry trade associations should carefully weigh in given the high stakes for future business development in certain areas of the country.

Clean Power Plan

The marquee greenhouse gas (GHG) rule from the Obama Administration was the Clean Power Plan (CPP). Finalized in August 2015, the rule is currently stayed pending completion of judicial review. The D.C. Circuit heard oral argument on the rule in September 2016 and could issue a decision at any time. Following the change in presidential administration, however, industry groups and the states petitioned for further judicial review of EPA’s denial of administrative reconsideration. This could ultimately delay a decision from the D.C. Circuit should the court require additional argument. Such delay could have broader consequences for the fate of the CPP given the change in personnel at EPA and the Department of Justice. However, as the CRS report notes, there is general agreement that whatever the decision from the D.C. Circuit, it will be appealed to the U.S. Supreme Court. In the meantime, the new EPA may amend the CPP through notice and comment rulemaking. Given the significance of this rule, whatever course EPA takes will undoubtedly be challenged in court. Thus, resolution on the CPP is unlikely any time soon. One fascinating aspect of the CPP, which also carries implications for the NSPS rules and BLM venting and flaring, is the use of the social cost of carbon and the social cost of methane to justify the costs of GHG rules. If the new administration takes a different economic approach, including abandoning social cost considerations all together, the agencies may have difficulty justifying these or similar GHG rules from a cost-benefit standpoint.

Other issues that did not make the CRS list include questions about what the new administration will do with the Obama Administration’s Climate Action Plan and Methane Strategy, whether it will target the GHG endangerment finding, and how the new EPA will interface with state regulatory bodies in terms of State Implementation Plan (SIP) review and enforcement strategy. Needless to say, all of these issues are creating unprecedented regulatory uncertainty with respect to the CAA and the associated rules for numerous business sectors. This ambiguity affects day-to-day operations as well as risk calculus and planning over the long term. For example, unlike the past several years, now may be a good time to take advantage of state and federal audit policy and voluntary disclosure programs to bring facilities and assets into compliance.

The authors have significant expertise in air quality regulation and frequently assist clients in planning for risks—both short- and long-term—posed by air quality rules and regulations. Please contact us if you have any questions about this alert.