On January 23, 2020, the Environmental Protection Agency and the Department of the Army, Corps of Engineers (collectively referred to as the “Agencies”) finalized the long-anticipated Navigable Waters Protection Rule (“2020 Rule”) to define “waters of the United States” regulated under the Clean Water Act (“CWA” or “Act”). The CWA establishes the basic structure for regulating discharges of pollutants into the nation’s “navigable waters,” which is vaguely defined in the Act as “waters of the United States, including the territorial seas.” This definition has proved difficult to apply to the myriad of different types of water bodies within U.S. jurisdiction, resulting in numerous judicial and administrative efforts to determine the scope of the CWA. The 2020 Rule is the final step in the Trump administration’s plan to replace the Obama administration’s definition of “waters of the United States” set forth in the 2015 Clean Water Rule (“2015 Rule”). To complete the first step, on October 22, 2019, the Agencies published the final rule to repeal the 2015 Rule (“Repeal Rule”) and returned to the pre-existing 1986 rule and subsequent agency guidance documents. The Repeal Rule became effective on December 23, 2019, although it has already been challenged in numerous actions filed in federal court.

The 2020 Rule redefines the nature and scope of the waterbodies that the Agencies have authority to regulate under the CWA. As instructed by Executive Order 13778 (February 28, 2017), the Agencies generally modeled the 2020 Rule on the four-justice plurality opinion authored by Justice Antonin Scalia in Rapanos v. United States, 547 U.S. 715 (2006), rather than the “significant nexus test” approach described in Justice Anthony Kennedy’s concurring opinion in that case. In addition to the 2020 Rule itself, the Agencies released numerous fact sheets and supporting documents, including an overview of the 2020 Rule and the manner in which the Agencies intend to implement the 2020 Rule. The Agencies also intend to hold a public webcast on the 2020 Rule on February 13, 2020.

Several of the key divergences from the 2015 Rule include:

• The four categories of waters that will be federally regulated under the 2020 Rule are: (1) the territorial seas and traditional navigable waters; (2) perennial and intermittent tributaries to those waters; (3) lakes and ponds, and impoundments of jurisdictional waters; and (4) wetlands that are adjacent to jurisdictional waters (other than waters that are themselves wetlands).

• By contrast, the 2015 Rule defined eight categories as waters of the U.S., incorporating significantly more waters into the definition of “waters of the United States” than will be covered by the 2020 Rule. Particularly relevant in the westernmost states, certain ephemeral streams and other ephemeral features, including some prairie potholes and western vernal pools, were regulated under the 2015 Rule. Ephemeral features are specifically excluded from the 2020 Rule’s definition.

• In addition, many wetlands that would have been regulated under the 2015 Rule as waters located within specified distances of jurisdictional waters will no longer be regulated because they are not physically “adjacent” to other jurisdictional waters as required by the 2020 Rule. “Adjacent wetlands” are now defined as “wetlands that abut or have a direct hydrological surface
  connection to other waters of the United States in a typical year.” This includes wetlands separated from jurisdictional waters only by a natural berm, bank, dune, or other similar natural feature but not other wetlands. A “typical year” is based on a rolling 30-year period and is the subject of an agency fact sheet.

• There are 12 categories of exclusions in the 2020 Rule. As noted, ephemeral features that flow only in direct response to precipitation, including ephemeral streams, swales, gullies, rills, and pools, are now excluded from the definition of “waters of the United States.” Diffuse stormwater runoff and directional sheet flow over upland are now also excluded. Some of the 2020 Rule exclusions were also exclusions in the 2015 Rule, including groundwater, certain waste treatment systems, artificially irrigated areas, artificial lakes and ponds in dry land, and previously converted cropland.

The 2020 Rule will go into effect 60 days after it is published in the Federal Register.

The Environmental Group of Davis Graham & Stubbs LLP works to ensure compliance, minimize potential exposure to environmental liability, and win cases when litigation arises. Please contact Zach Miller, Mave Gasaway, Andrea Bronson, or Kate Sanford if you would like to discuss these developments further or other water quality matters of concern to your company.

Three recent air quality developments will have a significant impact on regional oil and gas facilities: (1) the Colorado Air Quality Control Commission’s (“AQCC”) December 2019 rulemaking effort; (2) an expanded Environmental Protection Agency (“EPA”) Clean Air Act Audit Program for existing owners of oil and gas facilities; and (3) the EPA’s reclassification of Colorado’s Denver Metro/North Front Range ozone nonattainment area to Serious nonattainment. Each of these developments is addressed more specifically below, with links to relevant documents.

Colorado Air Quality Control Commission’s Rulemaking Effort

On December 19, 2019, the AQCC completed a rulemaking effort that significantly revised AQCC’s Regulation Numbers 3 and 7. The changes to the regulations are primarily aimed at achieving emission reductions from Colorado’s oil and gas industry. The AQCC’s amended regulations follow several months of stakeholder input and the approved changes largely track an initial proposal from the Air Pollution Control Division (“Division”).

Most notably, AQCC reorganized Regulation Number 7 and added several additional air pollution control, operational, and recordkeeping requirements effecting upstream oil and gas sources.

• The statewide storage tank control threshold was lowered to 2 tons per year (“tpy”).
• Air pollution controls are now required at storage tank truck loadout facilities. Specifically, an upstream oil and gas facility that has truck loadout throughput of more than 5,000 barrels per year must control truck loadout emissions.
• Oil and gas facilities now must submit an annual emission inventory of VOC, NOx, CO, methane, and ethane. Although the emissions inventory is subject to additional refinement and clarification in the coming months, recordkeeping requirements begin in July 2020 and the first emissions inventory report is due to the Division in January 2021.
• Leak detection and repair (“LDAR”) inspection frequencies were increased based on proximity to “Occupied Areas” as defined by Regulation 7. The exact implications of this new requirement are not yet entirely clear, but based on the draft regulatory language, well production facilities located within 1,000 feet of an Occupied Area must conduct alternate instrument monitoring method (“AIMM”) inspections on an increased frequency. Specifically, facilities with emissions greater than 12 tpy must conduct monthly LDAR inspections and facilities with emissions greater than 2 tpy andless than 12 tpy must conduct quarterly inspections. This change was proposed by a group of local communities and the AQCC’s adoption of the proposal was unexpected, not only because the Division did not support the alternate proposal, but also because the proposal’s language did not create clear or obvious compliance standards.
• LDAR frequency was increased state-wide for (1) semi-annual AIMM inspections of components at natural gas compressor stations with VOC emissions greater than 0 tpy and less than 12 tpy, and (2) Semi-annual AIMM inspections of components at well production facilities with VOC emissions equal to or less than 2 tpy and greater than 12 tpy.
• The AQCC promulgated a new comprehensive regulatory program for the natural gas transmission and storage segment. The program aims to reduce emissions from the transmission segment through an iterative performance-based program. The program requires operators to reduce methane emissions by meeting annual emissions intensity targets by using company specific best management practices (“BMPs”).
• The Commission adopted a requirement to employ storage tank measurement systems to determine the quantity of the liquid at well production facilities, natural gas compressor stations, and natural gas processing plants constructed on or after May 1, 2020. Accordingly, any facilities that are constructed after January 1, 2021, must have storage tank management systems in place that determine both quality and the quantity of the liquid. This requirement also applies to storage tanks at existing well production facilities, natural gas compressor stations, and natural gas processing plants that are modified by adding storage tanks.

The AQCC also changed several sections of Regulation Number 3 in the recent rulemaking. Of note, in an effort to clarify applicable regulatory deadlines, the AQCC revised the definition of Commencement of Operation for oil and gas well production facilities.

The final regulatory language is expected to be published in Colorado Register in January 2020 and become effective in February 2020.

The AQCC is expected to hold another significant oil and gas rulemaking hearing in late 2020. During the hearing, rule topics are expected to include regulation of preproduction emissions, zero bleed pneumatic controllers, increased LDAR repair time frames for facilities near occupied areas, and continuous methane emissions monitoring.

EPA’s Expanded Clear Air Act Audit Program for Oil & Gas Facilities

On December 19, 2019, EPA temporarily expanded its Clean Air Act audit program for oil and natural gas exploration and production facilities. The program is now available to current owners of upstream oil and natural gas facilities who voluntarily initiate a self-audit to identify, correct, and self-disclose Clean Air Act violations within the next twelve months. Note however, the program is not available if the EPA or a state has already discovered Clean Air Act noncompliance at oil and natural gas production facilities that an owner/operator proposes to audit under this Program, e.g., a notice of violation has been issued or there is an ongoing enforcement action or active investigation for violations at a facility.

Existing owners choosing to participate in the program must enter into the Existing Owner Program Agreement Template with EPA found here. A key component of the Agreement Template is that participating owners must assess storage tank battery vapor control system design. This design assessment is not necessarily otherwise required in all jurisdictions and thus compliance with the design assessment may be expensive for some owners and may require installation of various facility upgrades, in order to ensure the facility is properly designed. The Agreement Template also requires ongoing disclosures and updates to EPA during the course of the self-audit. However, in exchange, pursuant to the terms of the Agreement Template, the EPA will not impose civil penalties for violations that are discovered, corrected, and disclosed through the self-audit and the owner will not be subject to future enforcement action by the EPA as to the disclosed violations.

EPA’s Reclassification of Colorado’s Denver Metro/North Front Range Ozone Nonattainment Area to Serious Nonattainment

On December 26, 2019, the EPA reclassified the Denver Metro/North Front Range ozone nonattainment area (“Denver Area”) from Moderate to Serious nonattainment under the Clean Air Act.[1] In August 2019, based on an evaluation of air quality data collected from 2015 to 2017, EPA determined that the Denver Area did not meet the 2008 ozone national ambient air quality standards (“NAAQS”) within the relevant attainment timeframe and proposed that the Denver Area be reclassified to Serious nonattainment for ozone. After accepting public comment, the EPA issued its final redesignation of the Denver area as Serious nonattainment. The redesignation will become effective on January 27, 2020.

EPA’s action to reclassify the Denver Area requires Colorado to revise its State Implementation Plan, known as a SIP, in order to attain the 2008 ozone NAAQS and adopt new categories of controls, or reasonably available control technologies, on emissions sources. Colorado must submit SIP revisions to EPA by July 20, 2021.

One of the most notable impacts of the reclassification to Serious nonattainment is that within the Denver Area the air quality “major source” threshold lowers from the potential to emit (“PTE”) 100 tpy to 50 tpy of volatile organic compound (“VOC”) or oxides of nitrogen (“NOx”) emissions (precursors to ozone). This means that more oil and gas facilities in the Denver Area may be classified as “major sources” and will be subject to significantly more stringent, costly, and burdensome construction and/or operating permitting requirements. For example, new facilities that have the potential to emit between 50 and 100 tpy of VOCs previously would have been considered true or synthetic minor sources not subject to Non-Attainment New Source Review (“NANSR”) review, now will now be considered major sources and will be required to apply for and obtain a NANSR permit before construction. Additionally, existing sources with a potential to emit above 50 tpy of VOCs are also now required to submit a Title V application within 12 months of the effective date of the redesignation—January 27, 2021.

More sources will also be subject to Lowest Achievable Emission Rate (“LAER”), emission requirements, the most stringent emission limitation under the Clean Air Act which requires evaluation of the lowest achievable emission rate for the source, regardless of cost. Lastly, more sources will also be required to obtain emission offsets for new emissions of criteria pollutants at ratio of 1.2:1. Generally, this means that if a new source is expected to result in 50 tpy of VOC emissions, the applicant must identify 60 tpy in emission offsets elsewhere. Many affected sources were not subject to these requirements under the Moderate classification.

If Colorado continues to fail to attain the NAAQS by the applicable deadline or make reasonable further progress toward attainment, then the Denver Metro/North Front Range ozone nonattainment area may be again reclassified from Serious to Severe. As a Severe nonattainment area, the major source threshold will further drop from 50 tons per year PTE to 25 tons per year PTE. Major sources in a Severe area must obtain emission offsets for new emissions of criteria pollutants at ratio of 1.3:1. Finally, SIPs for severe ozone nonattainment areas must include sanction provisions, such as an emission fee on each major source off VOC emissions, to be collected by the state if the area misses its attainment deadline.

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 Randy Dann, Will Marshall, Shalyn Kettering, or Kate Sanford if you would like to discuss these three developments further, or other air quality matters of concern to your company.

[1]
The nonattainment area includes Boulder, Denver, Jefferson, Douglas, Broomfield, Adams, and Arapahoe Counties and parts of Larimer and Weld Counties.

The Public Utilities Commission (PUC) published a Notice of Proposed Rulemaking to amend its Rules Regulating Pipeline Operators and Gas Pipeline Safety (“Pipeline Safety Rules”). The Notice recommends significant proposed changes to the Pipeline Safety Rules and moving the Rules from their present location within the Gas Utilities and Pipeline Operator Rules at 4 Code of Colorado Regulations (CCR), 723-4, to a new, standalone Part 11, 4 CCR, 723-11. The PUC’s notice of the proposed rules states that, overall, the proposal is for “rule revisions that significantly alter and aim to improve upon pipeline safety oversight, both substantively and administratively, at the Commission.”

Broadly speaking, the proposed rules, available here, attempt to make the process around pipeline safety more public, clear, and transparent. For example, the proposed rules would require all filed reports to be publicly available and all Notices of Proposed Violation, Notices of Action, pleadings, and decisions to be filed publicly. The proposed rules also provide a revised methodology for calculating civil penalties in an effort to provide clarity to both operators and the public. Relatedly, the rules envision pared-down discretion for the Chief of Pipeline Safety and an increased procedural and oversight role for the PUC Commissioners.

The scope of the proposed rules includes all gas public utilities, all municipal or quasi-municipal corporations, transporting natural gas or providing natural gas services, all operators of master meter systems, and all operators of pipelines transporting gas in intrastate commerce. The last category includes gas gathering operators although certain provisions are tailored to the location and size of the gathering systems involved. A typographical error in the proposed rules included interstate pipelines within the scope. The federal government is the enforcement authority for interstate pipelines.

The purpose of the rules is to enforce and administer, in cooperation with the United States Department of Transportation, Pipeline Hazardous Materials Safety Administration (PHMSA), the provisions of the Natural Gas Pipeline Safety Act.

The proposed rules include updates for technical accuracy, recent changes in federal law, and general clarity. The Commission’s notice requested that stakeholders review the proposed technical updates and processes and comment on proposed revisions, clarity, or efficiencies.

Though the proposed rules aim to make pipeline safety information more transparent and publicly available than what exists under the current rules, there is some concern that such a wholesale rewrite of the rules was not preceded by a robust stakeholder process. The Notice invites stakeholders to continue to raise both rule and statutory considerations as well as statutory recommendations.

The proposed rules also solicit comments on a number of other matters: (1) whether additional rule considerations are necessary, (2) whether additional reporting or support, including mapping or other reporting considerations, should be provided in addition to, or as encompassed in, reports already provided; (3) whether, and to what extent, current and supplemental report filings should be publicly available, or if confidential protections are appropriate; and (4) whether to permit certain direction from the Chief of Pipeline Safety through the Commission’s website or other means that can be updated as needed.

In two other notable changes, the PUC first proposes a fee assessment in order to fund additional inspection staff and additional staff collaboration with other state and federal agencies that oversee pipeline safety. For gas distribution pipeline operators, the proposed fee would be per number of customers served. For gas gathering operators, the proposed fee would be per mile of pipeline as submitted on the operator’s annual report.

Second, the proposed rules include requirements specific to small operators, and the Notice specifically solicits comments from these small operator stakeholders regarding the staff’s proposed approach and seeks recommendations on improvements for the efficient and effective regulation of this operator group.

Written comments are requested by January 17, 2020. The Commission encourages commenters to file through the Commission’s E-Filing system at:

https://www.dora.state.co.us/pls/efi/EFI.homepage.

A filer must be registered to use the E-Filing system. Click on “Filer Registration” on the E-Filing homepage to register. All comments filed in the E-Filing System will be publicly available (without registration) by typing the proceeding number in the search box on the homepage. The proceeding number is: 19R-0703GPS. Responsive comments are requested on or before January 31, 2020. An administrative law judge will hold a hearing on the proposed rules at 9:00 a.m. on February 10, 2020 at the PUC’s offices, which are located at 1560 Broadway, Suite 250, Denver, Colorado. Interested persons may provide oral comments at the public hearing unless the ALJ deems oral presentations unnecessary.

Davis Graham & Stubbs LLP’s attorneys have experience with regulatory proceedings affecting the oil and gas sector and frequently represents clients in related rulemakings. Please contact Judy Matlock, John Jacus, or Shalyn Kettering for further discussion on this upcoming rulemaking.

In an Order issued on September 30, 2019, the United States Bankruptcy Court for the District of Colorado, construing Utah law, held that a Gas Gathering and Processing Agreement and a Salt Water Disposal Agreement each constituted covenants that run with the land and could not be extinguished through a Section 363 bankruptcy sale.[1]
In the Order, the bankruptcy court expressly distinguished the recent In re Sabine Oil & Gas Corp.
decision[2]
that sent shockwaves through the upstream and midstream segments of the oil and gas industry. As the first reported decision to test Sabine, this Order provides upstream and midstream companies as well as oil and gas and bankruptcy practitioners authority in contrast to Sabine that a midstream agreement which purports to burden hydrocarbon reserves or other real property (as opposed to simply burdening severed minerals) may be binding on successors in interest even after a “free and clear” bankruptcy sale.

Background

Badlands Energy, Inc., f/k/a Gasco Energy Inc., and certain related entities that owned and operated oil and gas assets in Utah (collectively, “Badlands”) filed for Chapter 11 bankruptcy in 2017. As part of the bankruptcy proceedings, Badlands auctioned and sold its oil and gas assets pursuant to Section 363 of the Bankruptcy Code. Following the auction, the bankruptcy court entered a “free and clear” sale order authorizing Badlands to sell a portion of its oil and gas assets known as the “Riverbend Assets” to Wapiti Utah, LLC (“Wapiti”).

Monarch Midstream, LLC (“Monarch”) owns and operates a gas gathering and salt water disposal system which services the Riverbend Assets. In 2010, Monarch acquired the then existing portions of this midstream infrastructure from Badlands, and in connection with the acquisition, Badlands and Monarch entered into a Gas Gathering and Processing Agreement (the “GGPA”) and an Agreement for Disposal of Salt Water (the “SWDA”). Under the terms of the GGPA, Badlands as Producer, dedicated and committed “. . . all Gas reserves in and under, and all Gas owned by Producer and produced from . . .” the leases and lands owned by Badlands within a defined geographic area (the “AMI”), whether now owned or thereafter acquired. The term of the GGPA runs until March 2025, and as to any wells connected to the gathering system, the GGPA would remain in effect so long thereafter as such wells were capable of producing in commercial quantities. Under the GGPA, Badlands was required to deliver a certain minimum volume of gas to Monarch each calendar quarter or else pay Monarch certain shortfall payments as liquidated damages.

Under the SWDA, Badlands committed to deliver all water requiring disposal from its operations within the AMI to Monarch’s disposal facilities. Both the GGPA and SWDA expressly stated that the dedication and commitment of gas or water, respectively, was a covenant running with the land.

As part of the Section 363 sale proceedings, Badlands rejected the GGPA and SWDA and therefore they were not assumed by, or assigned to, Wapiti. Monarch objected to the sale and filed an adversary proceeding seeking a declaratory judgment that the GGPA and SWDA could not be rejected because they constitute covenants running with the land. Monarch also asserted a breach of contract claim for $1.2 million in pre-petition fees due under the GGPA and SWDA. Pursuant to the Sale Order, Wapiti agreed to purchase the Riverbend Assets subject to the outcome of this adversary proceeding—provided, however, that if the bankruptcy court determined in the adversary proceeding that the Riverbend Assets could not be sold free and clear of the GGPA and SWDA, then such agreements would be deemed to be Permitted Encumbrances under the Asset Purchase Agreement and Wapiti, as buyer, would be responsible for the obligations under those agreements.[3]

Covenant Analysis Under Utah Law

Although the GGPA and SWDA are governed by Colorado law, the bankruptcy court ruled that, because property interests are created and defined by the law of the state in which the property is located, Utah law governed the determination of whether the GGPA and SWDA constitute covenants that run with the land.[4]

Applying Utah law, the bankruptcy court held that GGPA and SWDA are, in fact, covenants that run with the land. In order for a covenant to run with the land, it must possess four elements: (1) it must “touch and concern” the land, (2) the covenanting parties must intend for it to run with the land, (3) there must be privity of estate, and (4) the covenant must be in writing.[5]
Both the GGPA and SWDA are in writing, so the bankruptcy court focused its analysis on the other three elements.

Quoting extensively from Flying Diamond, the bankruptcy court held that the test for the “touch and concern” element does not require a physical effect upon the land but instead asks simply “ . . . whether a covenant enhances the land’s value [on the benefit side], and for the burden side, whether it diminishes the land’s value.”[6]
Moreover, all that must be shown is that the covenant “ . . . be of such character that its performance or nonperformance will so affect the use, value, or enjoyment of the land itself that it must be regarded as an integral part of the property.”[7]
The bankruptcy court found that the “touch and concern” element was met since the dedication and commitments in the GGPA and SWDA directly affect the Producer’s use and enjoyment of the leases and lands covered thereby. Furthermore, the purpose of the commercial terms of the GGPA and SWDA are to compensate Monarch for the cost and expense of installing and operating the gathering and disposal systems which are located on the producer’s lands and leases and connected to the producer’s wells.

In determining that the GGPA and SWDA touch and concern the land, the bankruptcy court distinguished Sabine. The bankruptcy court reasoned that the gas dedication in question in Sabine
covered all gas and condensate that were produced and saved from wells located within a defined geographic area. Since under Texas law extracted minerals are personal property—not real property—the Sabine court held that the “touch and concern” element was not met. Under Utah law, extracted minerals are also considered to be personal property and not real property. However, the bankruptcy court noted that the term “dedicated reserves” was broadly defined in the GGPA as “the interest of Producer in all Gas reserves in and under, and all Gas owned by Producer and produced or delivered from” the leases and other lands within the AMI.[8]
Since the dedication and commitment under the GGPA covered the gas reserves, not merely the produced gas, the bankruptcy court held that the dedication did in fact cover a real property interest. In addition, the bankruptcy court held that, unlike under Texas law in Sabine, a conveyance of real property is not required under Utah law to meet the “touch and concern” element in any event.[9]

In discussing the intent element, the bankruptcy court cited Flying Diamond
for the proposition that “an express statement in the document creating the covenant that the parties intend to create a covenant running with the land is usually dispositive of the intent issue.”[10]
Since both the GGPA and SWDA, along with the Memorandum of the GGPA, contain several express statements to that effect, the bankruptcy court held that the intent element was met. Interestingly, the Memorandum of the GGPA was never filed in the county records in the counties where the Riverbend Assets were located, and Wapiti argued that the failure to record the Memorandum was evidence that the parties did not intend for the GGPA to be a covenant that runs with the land. The bankruptcy court rejected that argument, noting that failure to record the Memorandum merely implicates notice, not intent, and there was no dispute that Wapiti had actual notice of the GGPA.[11]

Regarding the privity element, the bankruptcy court noted that traditionally, there are three types of privity: (1) vertical, (2) mutual, and (3) horizontal. Under Flying Diamond, vertical privity “arises when the person presently claiming the benefit, or being subject to the burden, is a successor to the estate of the original person so benefited or burdened.”[12]
The bankruptcy court held that vertical privity clearly exists in this case, since by its acquisition of the Riverbend Assets, Wapiti is the successor to Badlands as an original party to the GGPA and SWDA.[13]

Mutual privity exists when the parties have a continuing and simultaneous interest in the same property. However, the bankruptcy court observed that Utah has never adopted the requirement that mutual privity be shown, and that the Utah Supreme Court has noted that with respect to privity, substance should prevail over form.[14]
Although the bankruptcy court acknowledged that the fact scenario in Badlands “. . . is not identical to the traditional paradigm . . . [which] involves a property owner reserving by covenant, either for itself or another beneficiary, a certain interest out of the conveyance of the property burdened by the covenant . . .” the bankruptcy court concluded that the simultaneous interests of producer and gatherer in the lands and leases within the AMI satisfies mutual privity to the extent it is required under Utah law.[15]

“Horizontal privity exists when the original covenanting parties create a covenant in connection with a simultaneous conveyance of an estate.”[16]
Wapiti argued that, under Sabine, horizontal privity requires “. . . conveyance of an interest in property that itself is being burdened with the relevant covenant.” Since neither the GGPA nor the SWDA convey any real property interest in the mineral estate to Monarch, but rather conveyed only easements burdening the surface estate, Wapiti argued that horizontal privity was not met.[17]
However, the bankruptcy court held that, unlike Sabine, the commitment and dedication under the GGPA burdening the gas reserves, the conveyance of the then existing gathering and disposal infrastructure from Badlands to Monarch in connection with the execution of the GGPA and SWDA, and the grant of easements under the GGPA and SWDA each constitute a conveyance of real property, which all simultaneously burden the same leases and lands within the AMI.

As a result, the bankruptcy court concluded that all of the four elements were met and therefore that the GGPA and SWDA were covenants that run with the land comprising the Riverbend Assets.

Bankruptcy Law Analysis

Turning to application of the Bankruptcy Code, the bankruptcy court next held that covenants that run with the land, such as the GGPA and SWDA, are not “an interest” of which the Riverbend Assets could be sold free and clear of under Section 363(f).[18]
Under Utah law, the nature of a covenant that runs with the land is such that is must be regarded as an integral part of the property and binding upon successive owners of the burdened or benefitted land. Therefore, the GGPA and SWDA “. . . are part of the bundle of sticks that Wapiti acquired when it purchased the Riverbend Assets, and they are not subject to elimination utilizing Section 363(f).”[19]
Accordingly, Section 363(f)(1) cannot be relied on to enable Wapiti to acquire the Riverbend Assets free and clear of the GGPA and SWDA since it is not permitted by “applicable nonbankruptcy law” (i.e., Utah law). Section 363(f)(5) cannot be relied on either because “. . . Monarch could not be compelled . . . to accept money satisfaction of such interest because the interests of Monarch are part of the Riverbend Assets themselves.”[20]

Similarly, the bankruptcy court held that, because the GGPA and SWDA are covenants that run with the land under Utah law, they cannot be rejected under Section 365. Here, the bankruptcy court relied on Sabine in ruling that, under Section 365, “. . . it is not possible for a debtor to reject a covenant that runs with the land since such a covenant creates a property interest that is not extinguished through bankruptcy.”[21]

Not every aspect of the GGPA and SWDA survived the bankruptcy sale, however. Monarch sought to hold Wapiti liable for more than $1.2 million in fees incurred pre-petition under the GGPA and SWDA. The bankruptcy court disagreed. Assumption of executory contracts and the requirement to pay any attendant cure costs under such contracts are purely creatures of Section 365. Because Section 365 is not applicable to the GGPA and SWDA, there was no mechanism to require Wapiti to pay those prepetition amounts. Thus, a subsequent owner of land burdened by a real covenant takes subject to the covenant but is not liable for his predecessor’s breach.[22]
In other words, “while a covenant may run with the land, damages arising from broken covenants do not.” Accordingly, the bankruptcy court held that Monarch’s $1.2 million claim for pre-petition default is an unsecured claim against the bankruptcy estate for which Wapiti is not liable.[23]

Conclusion

Given the stakes at issue, the bankruptcy court’s decision will likely be appealed. Depressed commodity prices and other economic factors impacting the oil and gas industry are likely to result in additional oil and gas operators filing for bankruptcy. Debtors will continue to argue that these sorts of midstream agreements are simply executory contracts that do not create property interests that burden their assets; meanwhile, midstream providers will continue to argue that the obligations under the agreements do run with the land and that any conveyance will be subject to these covenants. Clearly, this issue will continue to arise and be further litigated.

While the bankruptcy court did not directly reject Sabine, this decision provides upstream and midstream companies as well as oil and gas and bankruptcy practitioners authority in contrast to Sabine that a midstream agreement which purports to burden hydrocarbon reserves or other real property (as opposed to simply burdening severed minerals) may be binding on successors in interest even after a “free and clear” bankruptcy sale.

If you have any questions relating to this decision or how it may affect your business, please contact Lamont Larsen, Chris Richardson, or Kyler Burgi.

Lamont Larsen

Mr. Larsen is a partner and the head of the Energy Group at Davis Graham & Stubbs LLP. His practice focuses on upstream and midstream transactional matters for the oil and gas industry. In particular, in recent years he has assisted several clients in acquiring oil and gas assets out of bankruptcy in Chapter 11 Section 363 auctions. He is licensed to practice in Colorado, Utah, Wyoming, North Dakota and Texas.

Chris Richardson

Mr. Richardson is a partner in the Finance & Acquisitions Department of Davis Graham & Stubbs LLP. His practice has an emphasis on mergers, acquisitions and corporate financing and restructuring work. Mr. Richardson has worked with secured and unsecured creditors, debtors, and creditors’ committees in numerous Chapter 11 proceedings. He has assisted clients and debtors in buying and selling companies out of Chapter 11, as well as reorganizing or liquidating debtor companies. He has also represented purchasers of oil and gas assets in Chapter 11 Section 363 auctions in bankruptcy proceeding in Wyoming, Colorado, Utah, North Dakota, and Delaware.

Kyler Burgi

Mr. Burgi is an associate in the Trial Department of Davis Graham & Stubbs LLP. His practice focuses primarily on complex commercial litigation, and bankruptcy & creditors’ rights.

[1] Monarch Midstream, LLC v. Badlands Production Co., f/k/a Gasco Production Co., Badlands Energy, Inc., f/k/a Gasco Energy, Inc., and Wapiti Utah, LLC, f/k/a Wapiti Newco, LLC (In re Badlands Energy, Inc.), United States Bankruptcy Court for the District of Colorado, Adv. Proc. No. 17-01429-KHT (hereafter, “Monarch v. Wapiti”).

[2] In re Sabine Oil & Gas Corp., 547 B.R. 66 (Bankr. S.D.N.Y. 2016); affirmed in In re Sabine Oil & Gas Corp., 567 B.R. 869 (S.D.N.Y. 2017) and In re Sabine Oil & Gas Corp., 734 Fed.Appx. 64 (2nd Cir. 2018).

[3]
See Order (A) Approving the Asset Purchase Agreement Between Debtor Badlands Production Company and Wapiti Utah, L.L.C.,(B) Authorizing the Sale of Substantially All of the Debtor’s Assets Free and Clear of All Liens, Claims, Encumbrances and Interests, (C) Authorizing the Assumption and Assignment of Contracts, and (D) Granting Related Relief, Docket No. 223, para. 39, In re Badlands Energy, Inc., et. al. Case No. 17-17465-KHT.

[4] Monarch v. Wapiti at 11.

[5] Id. at 12 (citing Flying Diamond Oil Corp. v. Newton Sheep Co., 776 P.2d 618, 624 (Utah 1989)).

[6] Id at 13.

[7] Id.

[8] Id. at 15 (emphasis in original)

[9] Id. at 14-15.

[10] Id. at 16.

[11] Id. at 17.

[12] Flying Diamond at 628.

[13] Monarch v. Wapiti at 17-18.

[14] Id. at 18-19.

[15] Id. at 20.

[16] Flying Diamond at 628.

[17] Monarch v. Wapiti at 21.

[18]
Section 363 (f)(1) states that a debtor may sell property free and clear of an interest only if “applicable nonbankruptcy law permits sale of such property free and clear of such interest.”

[19] Monarch v. Wapiti at 22.

[20] Id. at 22-23.

[21] Id. at 23; Sabine, 567 B.R. 869, 874.

[22]
In a somewhat curious provision, at the bottom of page 24 of the opinion, the bankruptcy court states that Wapiti took the Riverbend Assets free and clear of Monarch’s pre-petition claim because Monarch “could be compelled, in a legal or equitable proceeding, to accept money satisfaction of such interest.” Monarch v. Wapiti at 24. On page 22, the bankruptcy court held that Section 363 (f)(5) could not be used with respect to the covenant itself though apparently it can be used for claims that arise out of failure to comply with the covenant.

[23] Monarch v. Wapiti at 23-24.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Legal Alert Key Takeaways

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

2018 General Construction Permit Basics

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

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

Significant Changes in the 2018 General Construction Permit

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

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

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

Timing

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

CEOS

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

Conclusion

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

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

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

Case Study

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

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

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

Assessing the Risk

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

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

Assessment tools

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

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

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

1. What is the GDPR?

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

2. Who could violate the GDPR?

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

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

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

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

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

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

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

5. What is a “GDPR-valid” consent?

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

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

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

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

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

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

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

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

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

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

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

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

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