On November 30, 2022, the U.S. Bureau of Land Management (“BLM”) proposed new rules that would regulate the venting, flaring, and leaks of natural gas during oil and gas production activities on federal and Indian oil and gas leases (“Proposed Rule”). BLM is accepting public comments on the Proposed Rule through January 30, 2023.

Currently, BLM regulates venting and flaring of natural gas produced from federal and Indian leases through Notice to Lessees (“NTL”) 4A. In 2016, BLM finalized a rule that regulated venting, flaring, and leaks of natural gas during oil and gas production activities on federal and Indian oil and gas leases (the “2016 Rule”). In 2018, BLM attempted to administratively replace its 2016 Rule with another rule (the “2018 Rule”). Federal courts, however, vacated both rules in 2020, thus restoring NTL 4A as the governing source of authority over vented and flared gas from federal and Indian leases.

Earlier this year, Congress enacted a statutory provision affecting when royalty is due on vented and flared gas. In section 50263 of the Inflation Reduction Act of 2022, Public Law No. 117-169, Congress mandated that, for all federal leases issued after August 16, 2022, royalty is due on all produced gas, except (a) gas vented or flared for not longer than 48 hours in an emergency situation that poses a danger to human health, safety, or the environment; (b) gas used or consumed within a lease, unit, or communitized area for the benefit of the lease, unit, or communitized area; and (c) gas that is unavoidably lost.

The Proposed Rule attempts to rectify the legal infirmities in the 2016 and 2018 Rules and incorporate the legislative change. Most notably:

• Like its predecessors, the Proposed Rule defines whether gas is “avoidably lost” and thus royalty bearing, or “unavoidably lost” and thus royalty-free.
• The Proposed Rule would allow BLM to evaluate potential flaring when approving applications for permits to drill (“APDs”). It would allow BLM to attach conditions of approval to APDs to require reasonable measures to prevent waste of natural gas. The Proposed Rule would also require operators to submit waste minimization plans with APDs and would allow BLM to defer or deny APDs to avoid unreasonable and undue waste.
• The Proposed Rule contains provisions specifically addressing two comment reasons for flaring: emergencies and limited pipeline capacity.
  • The Proposed Rule narrowly defines “emergency situations” and allows only 48 hours of royalty-free flaring in emergency situations
  • The Proposed Rule would allow for royalty-free flaring of up to 1,050 Mcf of oil-gas per month, per lease, unit, or communitized area (“CA”) because of pipeline capacity constraints, midstream processing failures, or similar events.
  • The Proposed Rule would allow BLM to require operators to curtail or shut-in production when significant flaring occurs because of pipeline capacity constraints, midstream processing failures, or similar events.
• The Proposed Rule contains similar operational limitations and equipment requirements as the 2016 Rule, including limitations on flaring during well completions and initial production tests; equipment requirements for pneumatic controllers and storage vessels; and leak detection and repair (“LDAR”) requirements.
  • The Proposed Rule would reduce the volumes of royalty-free flaring that may occur during well completions and initial production tests from the volumes of royalty-free flaring authorized by NTL 4A.
• Citing safety concerns, the Proposed Rule would prohibit venting except in specified circumstances.
• The Proposed Rule would allow states and Tribes to apply for variances from specific provisions.

These proposals are described in more detail below.

Notably, the Proposed Rule is narrower in scope than the 2016 Rule. Whereas the 2016 Rule applied to all oil and gas wells within a unit or communitized area with federal or Indian leases, the Proposed Rule’s provisions relating to safety, pneumatic equipment, storage tanks, and LDAR at sections 3179.6, 3179.201, 3179.203, and 3179.301 – .303 only apply to operations “on a [f]ederal or Indian lease.” The Proposed Rule does not define “on a [f]ederal or Indian lease,” thus raising a question of whether the final rule would apply to surface facilities physically within the boundary of a lease or to wells that penetrate federal or Indian leases, regardless of the location of surface facilities. The remaining provisions of the Proposed Rule apply to all operations producing federal and Indian oil and gas because they have the potential to impact royalty revenues more significantly.

Avoidably & Unavoidably Lost Gas

Section 3179.4(c) of the Proposed Rule defines gas as “avoidably lost” if it is not “unavoidably lost.” Section 3179.4(a) and (b) then sets forth a variety of circumstances when gas is unavoidably lost. First, section 3179.4(a) and (b) defines gas as “unavoidably lost” when the operator “has not been negligent, . . . has taken prudent and reasonable steps to avoid waste, . . . and has complied fully with applicable laws, lease terms, regulations, provisions of a previously approved operating plan, and other written orders of the BLM.”

Second, section 3179.4(b) defines gas as unavoidably lost when it is lost from the following operations or sources, which are subject to operational limitations or constraints set forth in other provisions of the Proposed Rule:

• Well drilling, unless BLM determines gas was lost due to operator negligence as provided in section 3179.101;
• Well completion and related operations, subject to the limitations in section 3179.102;
• Initial production tests, subject to the limitations in section 3179.104;
• Emergency situations, subject to the limitations in section 3179.105;
• Normal operating losses from a natural-gas-activated pneumatic controller or pump, subject to requirements in section 3179.201;
• Normal operating losses from a storage vessel or other low-pressure production vessel that is in compliance with sections 3179.203 and 3174.5(b);
• Well venting in the course of downhole well maintenance and/or liquids unloading performed in compliance with section 3179.204;
• Leaks, when the operator has complied with LDAR requirements in sections 3179.301 and .302; and
• Pipeline capacity constraints, midstream processing facilities, or other similar events, subject to limitations in section 3179.8.

Additionally, section 3179.4(b) defines gas as unavoidably lost when it is lost from the following operations or sources, which are not subject other limitations or constraints set forth in other provisions of the Proposed Rule:

• Exploratory coalbed methane well dewatering;
• Facility and pipeline maintenance, such as when an operator must blow-down and depressurize equipment to perform maintenance or repairs;
• Flaring of gas from which at least 50 percent of natural gas liquids have been removed and captured for market; and
• Flaring of gas from a well not connected to a gas pipeline if BLM authorized the flaring in its approval of the APD.

Evaluation of Flaring at the APD Stage

Conditions of Approval to APDs

• The Proposed Rule would allow BLM to attach conditions of approvals to APDs specifying “reasonable measures” to prevent waste. § 3179.12(b).
• After approval of an APD, BLM may order an operator to implement additional “reasonable measures” to prevent waste. § 3179.12(c).
• The Proposed Rule describes “reasonable measures” to prevent waste as reflecting “factors including but not limited to relevant advances in technology and changes in industry practice.” § 3179.12(d).

Waste Minimization Plans

• The Proposed Rule would require operators to include with all APDs a waste minimization plan that demonstrates how the operator plans to capture gas upon the start of production or as soon thereafter after reasonably possible. § 3162.3-1(j).
• For oil wells, if BLM determines that drilling the could cause “unreasonable and undue waste,” BLM may approve an APD with conditions for gas capture or royalty payment. Alternatively, BLM may defer approving the APD to prevent waste.
  • BLM may deny the permit after deferring for two years if the potential for “unreasonable and undue waste” is not addressed. § 3162.3-1(k).
  • The Proposed Rule would define “unreasonable and undue waste” as “a frequent or ongoing loss of gas that could be avoided without causing an ultimately greater loss of equivalent total energy that would occur if the loss of gas were to continue unabated.” § 3179.3.
  • BLM explained that it views the concept of “unreasonable and undue waste” as informing BLM decision-making with respect to complicated waste prevention measures, such as delaying or denying a permit to drill or ordering a well to be shut-in due to excessive flaring. By contrast, BLM views the “avoidable/unavoidable loss” designation primarily as a means to determine when royalties must be paid on lost gas.

Common Flaring Events – Emergencies & Pipeline Capacity

Emergencies

• The Proposed Rule would allow 48 hours of royalty-free flaring or venting in “emergency situations.” § 3179.105(a).
• The Proposed Rule defines an “emergency situation” as “a temporary, infrequent, and unavoidable situation in which the loss of gas is necessary to avoid a danger to human healthy safety, or the environment.” § 3179.105(a).
• The Proposed Rule affirmatively states the following situations are not emergencies:
  • Recurring failures of the same piece of equipment;
  • The operator’s failure to install appropriate equipment of a sufficient capacity to accommodate production conditions;
  • Failure to limit production when the production rate exceeds the capacity of the related equipment, pipeline, or gas plant, or exceeds sales contract volumes of oil or gas;
  • Scheduled maintenance; or
  • Operator negligence.

Pipeline Capacity & Midstream Processing Failures

• The Proposed Rule allows for royalty-free flaring of up to 1,050 Mcf of oil-well gas per month, per lease, unit, or CA because of pipeline capacity constraints, midstream processing failures, or other similar events that prevent produced gas from being transported through the connected pipeline. § 3179.8(a).
• The Proposed Rule would allow BLM to order an operator to curtail or shut in production where “substantial volumes” of oil-well gas is flared. § 3179.8(b).
  • The Proposed Rule expressly states that BLM will not order curtailment or a shut-in of production unless the operator has reported flaring of more than 4,000 Mcf per month for three consecutive months and the flaring is ongoing. § 3179.8(b).
• The Proposed Rules would allow BLM to order curtailment or a shut-in of production, resulting in adverse effects to production of non-federal or non-Indian oil and gas, only if the applicable unit or communitization agreement allows BLM to regulate the rate of production.

Flaring and Venting During Drilling and Production

• Well drilling – §3179.101.
  • BLM may determine that operator negligence caused the loss of well control and thus loss of gas. In that circumstance, lost gas is availably lost and royalty bearing.
• Well completion and related operations – § 3179.102.
  • For new completions that are hydraulically fractured, the Proposed Rule allows 10,000 Mcf of gas to be flared royalty-free during well completion, post-completion, and fluid recovery operations.
  • For recompletions of wells connected to a gas pipeline, the Proposed Rule allows 5,000 Mcf of gas to be flared royalty-free during well completion, post-completion, and fluid recovery operations.
• Initial production testing – § 3179.103.
  • The Proposed Rule allows royalty-free flaring during initial production tests for 30 days or until the operator flares 20,000 Mcf, whichever occurs first.
    • The 20,000 Mcf includes volumes flared during well completions and related operations under § 3179.102.
  • BLM may extend the 30-day period up to an additional 60 days because of well or equipment problems or because of a need for further testing.
  • BLM may increase the 20,000 Mcf limit by up to an additional 30,000 Mcf for exploratory oil wells in remote locations where additional information is needed in advance of development of pipeline infrastructure.
• Subsequent well tests – § 3179.104.
  • The Proposed Rule would allow royalty-free flaring for 24 hours for subsequent well tests unless BLM approves a longer period.

Equipment and Well Maintenance Requirements

• Pneumatic controllers and pumps – § 3179.201.
  • One year after the final rule takes effect, natural gas-activated pneumatic controllers and pneumatic diaphragm pumps with a bleed rate that exceeds 6 standard cubic feet (scf) per hour may not be used on leases, unit participating areas (“PAs”), or CAs that are producing at least 120 Mcf or 20 barrels of oil per month.
• Tanks – § 3179.203.
  • One year after the final rule takes effect, all oil storage vessels must be equipped with a vapor-recovery system or other mechanism to avoid the intentional loss of natural gas, unless the operator determines that a vapor-recovery system or other mechanism is technically or economically infeasible.
    • When a storage vessel is not equipped with a vapor-recovery system or other mechanism, the operator must submit a sundry notice to BLM with an annual compositional analysis production from the storage vessel. The compositional analysis must meet requirements identified in § 3179.203(c).
  • Operators must flare, rather than vent, of gas released from an oil storage vessel when practical and safe.
  • Operators may commingle vapors from multiple storage vessels to a single flare without BLM’s prior approval.
  • BLM will impose an immediate assessments of $1,000 for a thief hatch left open and unattended.
• Downhole well maintenance and liquids unloading – § 3179.204.
  • Gas vented or flared during well maintenance and well purging is royalty-free for a period not to exceed 24 hours per event.
    • “Well purging” means blowing accumulated liquids out of a wellbore by reservoir gas pressure, whether manually or by an automatic control system, where gas is vented to the atmosphere. It does not apply to wells equipped with a plunger lift system.
  • Gas vented or flared from a plunger lift system and/or an automated well control system is royalty free.
  • Operators must minimize gas losses during well maintenance and well purging.
    • For wells equipped with a plunger lift system and/or an automated well control system, minimizing gas less includes optimizing the operation of the system to minimize gas losses, to the extent possible.
    • For liquids unloading by manual well purging, the person conducting the well purging must remain on-site throughout the event.

Leak Detection and Repair (LDAR) Requirements

• LDAR programs – § 3179.301.
  • Operators must maintain LDAR programs.
  • LDAR inspections must occur annually.
    • For leases in effect when the final rule takes effect and on which operations have commenced, the operator must conduct an initial inspection within one year of the effective date of the final rule.
    • For other leases, the operator must conduct an initial inspection within one year of commence of operations.
  • Operators must submit a sundry notice to BLM describing their LDAR programs.
    • For leases in effect when the final rule takes effect, the operator must submit the sundry notice within six months of the effective date of the rule.
    • For new leases, the operator must submit the sundry notice within six month of a lease’s issuance.
    • BLM will review the LDAR program and notify the operator if BLM deems the program to be inadequate.
• Leak repair – § 3179.302.
  • Leaks must be repaired as soon as practicable and within 30 calendar days after discovery, unless the repair is technically infeasible (including unavailability of parts), would require a pipeline blowdown, a compressor shutdown, or a well shut-in, or would be unsafe to conduct during operation of the unit.
  • If the repair is delayed over 30 days, the operator must submit a sundry notice notifying BLM of the cause. BLM will not approve delays of over two years.
  • The operator must verify the effectiveness of a repair within 30 days of completing the repair.
• Leak detection inspection recordkeeping and reporting – § 3179.303.
  • By March 31 of each year, operators must submit an annual summary report to BLM on the previous year’s inspection activities.
  • Operators must retain records related to leak inspection and repair as specified in the rule.

Venting Prohibition

Citing safety concerns, section 3179.6 of the Proposed Rule would require operators to flare, rather than vent, gas that is not captured, except:

• When flaring is technically infeasible, such as when volumes are too small to flare;
• Under emergency conditions, when the loss of gas is uncontrollable or venting is necessary for safety;
• When gas is vented through a natural-gas-activated pneumatic controller or pump, a storage vessel, downhole well maintenance or liquids unloading activities, or a leak;
• When venting is necessary to allow non-routine facility and pipeline maintenance; and
• When release of gas is necessary and flaring is prohibited by federal, state, local, or tribal law or regulation, or the term of a permit.

Measurement Requirements

• The Proposed Rule would impose specific measurement requirements on high-pressure flares flaring 1,050 Mcf or more per month. § 3179.9(b). The Proposed Rule would allow estimation of volumes flared from other flares. § 3179.9(c).
• The Proposed Rule would allow gas produced from multiple leases, unit PAs, or communitized areas to be combined at a single flare using an allocation method approved by BLM. § 3179.9(d).
• The Proposed Rule specifies that measurement points for flared volumes are not facility measurement points. § 3179.9(e).

Variance Procedures

• Section 3179.401 would allow States and Tribes may apply for variances from any provision of the BLM’s final rule. BLM has discretion to approve such a request if BLM finds that State, local, or Tribal regulations or rules would perform at least equally well as the provision of BLM’s rule from which the variance is sought to a) reduce waste of oil and gas; b) reduce environmental impacts from venting and/or flaring of gas; c) assure appropriate royalty payments to the United States or beneficial Indian owners; and d) ensure the safe and responsible production and oil and gas.

Today, the United States Bureau of Land Management (BLM) published a notice of intent to prepare a programmatic environmental impact statement (PEIS) to modify and update its 2012 Western Solar Plan (“2012 Plan”) and make necessary resource management plan (RMP) amendments. The notice initiated a 60-day scoping period during which BLM will accept public comment on the PEIS and potential RMP amendments.

The 2012 Plan established where and how utility-scale solar energy development could occur on BLM-managed lands in Arizona, California, Colorado, Nevada, New Mexico, and Utah. Specifically, the 2012 Plan amended RMPs in these states to exclude some lands from solar development, identify lands where solar development would be prioritized (solar energy zones or “SEZs”), and establish a process for development outside of SEZs (in “variance areas”).

The PEIS will evaluate potential modifications to improve and expand the 2012 Plan. In the notice of intent, BLM explained that the 2012 Plan facilitated solar development applications in areas of flat land and direct sunlight and in areas without high-value resources. Solar developers, however, have expressed interest in development in areas allocated as exclusion areas based on exclusion criteria for slope or solar insolation values. Accordingly, BLM now seeks to update the 2012 Plan.

BLM particularly has identified these objectives of the planning process:

• To focus the BLM’s utility-scale solar energy planning on resource management on BLM-administered lands rather than specifying technology-based criteria for solar development on public lands;
• To expand the solar program to additional states;
• To increase opportunities for renewable energy development in priority and variance areas; and
• To develop appropriate criteria to exclude high-value resource areas from renewable energy development.

The PEIS also may consider land use allocation modifications related to other renewable energy development types, such as wind energy.

In its notice, BLM explained that it would consider alternatives in the PEIS that would modify these aspects of the 2012 Plan:

• Study area. BLM will consider at least one alternative that would expand BLM’s solar program to portions of additional states, which may include Idaho, Montana, Oregon, Washington, and Wyoming. BLM will also consider whether to include in the PEIS study area lands covered by the Desert Renewable Energy Conservation Plan in California and the Restoration Design Energy Project in Arizona.
• Exclusion criteria. BLM will consider whether to eliminate two exclusion categories and modify the remaining exclusion categories established in the 2012 Plan. Particularly, BLM will consider eliminating exclusion criteria 1 (excluding development in locations with slopes greater than five percent) and 2 (excluding development where insolation values are below 6.5 kWh/m²/day).
• Land use allocations. BLM will consider at least one alternative that would adjust existing SEZs, variance areas, and exclusion areas. BLM would consider establishing new SEZs, variance areas, and exclusion areas, including in states not covered by the 2012 Plan.
• Variance process. BLM will consider modifications to the variance process to focus review and improve efficiency. These potential modifications follow recent BLM’s release of an Instruction Memorandum
  aimed at enhancing consistency and workflow efficiency in the variance process. Notably, BLM will consider whether to incorporate variance procedures in means other than the PEIS, such as regulation or policy. BLM will also consider whether the purpose of the variance process is being met through other mechanisms, such as site-specific environmental review and BLM’s review of right-of-way applications, and therefore whether to continue the variance process.
• Definition of utility-scale. BLM may revise the definition of “utility-scale” set forth in the 2012 Plan, which is any project capable of generating 20 or more megawatts (MW) of electricity that is delivered into the electricity transmission grid.
• Promoting development in SEZs. BLM will consider incentives to promote development in SEZs.

BLM will hold two virtual and 12 in-person public meetings as part of the scoping process. BLM has requested that the public submit comments by February 6, 2023, via its eplanning site.

Please contact Katie Schroder with questions about the PEIS or how to effectively participate in the scoping process.

The U.S. Fish and Wildlife Service (USFWS) has released a final rule listing distinct population segments of the lesser prairie-chicken as threatened and endangered under the Endangered Species Act (ESA) (“Listing Rule”) based, in part, on threats from conventional and renewable energy development. The Listing Rule will become effective on or about January 25, 2023, which is 60 days after the Listing Rule is published in the Federal Register.

The USFWS listed the lesser prairie-chicken as endangered in New Mexico and west Texas. The USFWS listed the lesser prairie-chicken as threatened in the remainder of its range.

More precisely, the lesser prairie-chicken exists in the Texas Panhandle, eastern New Mexico, western Oklahoma, western Kansas, and southeastern Colorado. In these areas, lesser prairie-chicken populations exist in four distinct ecoregions: (1) a Shinnery Oak Ecoregion in New Mexico and Texas; (2) a Mixed-Grass Ecoregion of Oklahoma, Kansas, and Texas; (3) a Short Grass/Conservation Reserve Program (CRP) Ecoregion in Kansas and Colorado; and (4) a Sand Sagebrush Ecoregion in Colorado, Oklahoma, and Kansas.

In the Listing Rule, the USFWS applied its Distinct Population Segment policy, 61 Fed. Reg. 4722 (Feb. 7, 1996), and found that the lesser prairie-chicken population in the Shinnery Oak Ecoregion qualifies as a DPS (“Southern DPS”) and that the population in the three northern ecoregions qualifies as a separate DPS (“Northern DPS”). The USWFS then listed the Southern DPS as endangered and the Northern DPS as threatened.

Notably, the USFWS did not designate, and has not proposed to designate, critical habitat. The USFWS found that critical habitat presently is not determinable because the USFWS lacks information sufficient to perform the required analysis of the impacts of a critical habitat designation.

For energy developers and most other land users, no difference exists between the endangered listing of the Southern DPS and threatened listing of the Northern DPS. The USFWS’s listing of the Southern DPS as endangered and the Northern DPS as threatened carry the same the restrictions – most notably, the prohibition on take and incidental take of the lesser prairie-chicken. Although the USFWS has proposed to exempt a handful of activities in the Northern DPS from the prohibition on incidental take pursuant to section 4(d) of the ESA, these activities mainly relate to agricultural practices and prescribed fire.

Because incidental take of LPC resulting from conventional and renewable energy development will be prohibited once the Listing Rule takes effect, an energy developer must obtain a permit under section 10 of the ESA to engage in activities that incidentally take an LPC. Several permits are available to conventional and renewable energy developers:

• The USFWS has developed conservation plans, known as Candidate Conservation Agreements with Assurances (CCAAs), that authorize incidental take from oil and gas activities by operators who enrolled in the plans prior to the listing of the lesser prairie-chicken.
• The USFWS has finalized a habitat conservation plan (HCP) and issued a section 10 permit for oil and gas upstream and midstream activities. The section 10 permit associated with this HCP authorizes incidental take of lesser prairie-chicken by parties who execute a certificate of inclusion with the permit holder and commit to conservation measures as provided in the HCP. The HCP and related materials are available here. Unlike the oil and gas CCAAs, parties may enroll in the HCP after the USFWS’s listing decision takes effect.
• The USFWS has finalized an HCP and issued a section 10 permit for wind and solar energy, power lines, and communication towers. Like the oil and gas section 10 permit and HCP, the section 10 permit associated with this HCP authorizes incidental take of lesser prairie-chicken by parties who execute a certificate of inclusion with the permit holder and commit to conservation measures as provided in the HCP. The HCP and related materials are available here. Parties may enroll in the HCP after the USFWS’s listing decision takes effect.

Energy developers operating in a lesser prairie-chicken ecoregion should evaluate the risk that their activities will result in incidental take of lesser prairie-chicken and evaluate whether to enroll in an HCP.

Additionally, energy developers that will require a new federal permit or right-of-way should anticipate a longer permitting process, particularly in New Mexico where the United States holds a considerable amount of surface and mineral estate. Before a federal agency such as the Bureau of Land Management (BLM) may approve a permit or grant a right-of-way that may affect the lesser prairie-chicken, it must consult with the USFWS under section 7 of the ESA. The duration and complexity of this consultation depends on the potential impacts to the lesser prairie-chicken resulting from the federal approval or grant. Notably, delays may be reduced for land users enrolled in the Candidate Conservation Agreement (CCA) between the USFWS and BLM in New Mexico because the agencies have already engaged in some consultation under section 7 of the ESA over activities covered by the CCA.

If you have questions about the impact of the listing of the lesser prairie-chicken on your permits or operations, please contact Katie Schroder.

Global cryptocurrency exchange FTX Trading, Alameda Research, and 132 of their affiliates filed voluntary Chapter 11 bankruptcy petitions on November 11, 2022. According to the petitions, the debtors have more than 100,000 creditors. The cases have been assigned to Judge John T. Dorsey in the U.S. Bankruptcy Court for the District of Delaware.

FTX’s Chapter 11 filing has destabilized the crypto industry. Our attorneys are prepared to help clients navigate this landmark bankruptcy and are monitoring advancements in the case. Please contact Davis Graham attorneys Adam L. Hirsch, Chris Richardson, Kyler Burgi, or Peter H. Schwartz if we can assist in any way.

On September 15, 2022, U.S. Deputy Attorney General (DAG) Lisa O. Monaco issued a memorandum
and delivered prepared remarks announcing important policy updates in the Department of Justice’s (DOJ) efforts to fight corporate crime. The new policies build off of a preceding memorandum issued in October 2021 and signal a continued re-orientation towards holding culpable individuals responsible for corporate crime while encouraging companies to self-report, cooperate with investigators, and build strong compliance structures and culture. With the right mix of incentives and deterrence, DAG Monaco explained, shareholders will no longer be forced to bear the consequences of misconduct.

Key Takeaways:

• Individual Accountability: DAG Monaco emphasized that going after individuals who commit and profit from corporate crime was DOJ’s “top priority.” To that end, time is of the essence. Observing that individual prosecutions are too often slowed by a company’s reluctance to cooperate with prosecutors or spend the time and money to remediate misconduct, DOJ’s new policies incentivize companies to produce “hot” documents or evidence sooner during a company’s investigation process. Such timely disclosures will be rewarded with greater cooperation credit, while undue or intentional delay will result in the reduction or denial of such credit. In addition, DOJ will require its prosecutors to complete investigations and seek any criminal charges against individuals prior to or at the same time as entering a resolution against a corporation. According to DAG Monaco, both prosecutors and corporate counsel should feel like they are “on the clock.”
• History of Misconduct: Consistent with her October 2021 remarks, DAG Monaco explained that DOJ’s new policies required that prosecutors take a holistic look at a company’s misconduct history in determining an appropriate remedy or punishment. For repeat offenders—especially when involving the same personnel—DOJ will heavily scrutinize successive non-prosecution or deferred prosecution agreements and will not shy away from bringing charges or requiring guilty pleas. For others, the DOJ recognizes that not all misconduct is created equal and will accord less weight to criminal misconduct older than 10 years and civil or regulatory resolutions older than 5 years in determining appropriate punishment.

• Voluntary Self-Disclosure: DOJ has long encouraged voluntary self-disclosure of corporate misconduct. Emphasizing the importance such disclosure plays in creating a healthy compliance culture and timely resolutions, DAG Monaco explained that every DOJ component engaged in corporate enforcement will implement a program to encourage and reward voluntary disclosures. As an incentive, DOJ will not seek a guilty plea from the company when a company has voluntarily self-disclosed, cooperated, and remediated its conduct, absent aggravating factors. Nor will DOJ require an independent compliance monitor if the company has an implemented an effective compliance program.

• Independent Compliance Monitors: DAG Monaco explained that DOJ’s policies provide new guidance to prosecutors on how to identify the need for a monitor, how to select a monitor, and how to oversee the monitor’s work to increase the likelihood of success. In addition, the selection process for monitors will be transparent and consistent, and the selection of monitors will be tailored to the misconduct and corresponding compliance deficiencies. Prosecutors will ensure that all monitors stay on task and on budget.

• Corporate Culture: DAG Monaco also made clear that DOJ will pay close attention to company compliance programs that effectively reduce financial incentives for corporate wrongdoing, such as by clawing-back or escrowing an individual wrongdoer’s compensation. DOJ will require companies to show how they are linking compensation to compliance. Prosecutors are now directed to not only consider what the company’s policies say, but whether the company is following those policies in practice. New guidance on how to reward companies that implement compensation-based compliance programs is expected by the end of the year.

Implications:

According to DAG Monaco, the math is simple: root out misconduct and save time, money, and your reputation; otherwise, be prepared to face harsh consequences. DOJ’s new corporate criminal policies signal a renewed and strengthened focus on punishing corporate wrongdoing. To prepare for these changes, companies should:

• Invest in effective compliance programs that dedicate appropriate resources to early identification of misconduct, discovery and disclosure of documents or evidence of individual culpability, and remediation of misconduct. As the new DOJ policies make clear, leniency flows to those that voluntarily self-disclose
• Strengthen their corporate compliance culture by reviewing and, if necessary, updating compensation policies and incorporating forthcoming guidance on how to implement compensation-based compliance programs.

• Seek to hold individual wrongdoers accountable and, where appropriate, ensure early and robust cooperation with investigators.

• Review the prior misconduct of the company and of any entities acquired through mergers or acquisitions to better gauge how such history may affect a prosecutor’s evaluation of any punishment for future misconduct.

• Consult with experienced counsel early and often if facing allegations of corporate wrongdoing or an investigation or enforcement actions by the government.

  Please contact a Davis Graham partner if we can assist you in any way.

The Colorado legislature recently enacted a law, patterned on the federal False Claims Act, that creates new liability risks for businesses receiving or using state funds. The Colorado False Claims Act (the “CFCA”) was passed by the General Assembly in early June, signed into law by Governor Polis on June 7, 2022, and takes effect in September 2022. Like its federal counterpart, the CFCA holds individuals and businesses liable for committing, conspiring to commit, or aiding and abetting the commission of what the law characterizes as “false claims.” Such claims include false claims for payment from state funds, false records relating to claims for state payments, and withholding and misuse of state funds. The CFCA authorizes hefty civil penalties to protect public funding from misuse and misappropriation: between $11,800 and $23,600 per violation plus three times the amount of the damages sustained by the state as a result of the false claim.

In addition to authorizing civil penalties for false claims on state funds, the CFCA also empowers, protects, and rewards whistleblowers who sound the alarm on fraud against the state. This is typically seen in the case of employees blowing the whistle on their employers. The CFCA allows such employees and any other public citizens to file qui tam lawsuits on behalf of the state against those who make false claims for state funds. In the event of a successful qui tam suit, whistleblowers stand to recover up to 30% of any funds recouped by the government, “based on the extent the [whistleblower] contributed to the investigation and prosecution of the false claim.” The CFCA also protects whistleblowers from any form of retaliation, including – in the case of whistleblowing against an employer – discrimination, demotion, or termination because of the whistleblower’s “efforts in furtherance of investigating, prosecuting, or stopping false claims.” Additionally, the CFCA authorizes the Colorado Attorney General and local prosecutors to investigate false claims, seek penalties, and intervene in qui tam cases brought by whistleblowers.

Although the impact of the CFCA will not be known until after it takes effect in September, it has the potential to significantly incentivize individuals to blow the whistle on employers who receive or use state funds for any kind of statements or conduct that could be characterized as false or misleading. Under the federal False Claims Act, after which the CFCA is modeled, whistleblowers have been awarded over $8 billion and assisted the federal government in recovering over $70 billion since 1986, including over $5.6 billion in 2021 based on false claims relating to, among other things, federal health care funds (Medicaid, Medicare, etc.), unlawful kickbacks by businesses, unnecessary medical services, government procurement fraud, and COVID-related fraud.

As a result of the protection on whistleblowers and the financial incentive to blow the whistle, the CFCA may result in businesses facing more enforcement suits – whether meritorious or not. With implementation of the CFCA imminent, our attorneys are ready to help companies navigate this new law and its potential impact on their business, including by ensuring appropriate compliance mechanisms are in place to help prevent false claims from occurring.

Last week, an environmental non-governmental organization challenged the Bureau of Land Management’s (BLM) policy for approving horizontal wells sited on off-lease, non-federal surface. Particularly, on July 22, 2022, Western Watersheds Project filed a lawsuit in the U.S. District Court for the District of Columbia challenging the BLM’s Permanent Instruction Memorandum No. 2018-014 (IM 2018-014), which provides guidance on how the BLM permits horizontal wells drilled from off-lease pads sited on non-federal surface. These wells are more easily visualized than described:

IM 2018-014 is conventionally known as the “Fee/Fee/Fed IM,” which refers to a well sited on fee surface above fee minerals that is drilled into a federal oil and gas lease.

IM 2018-014 provides the BLM with three general sets of directions. First, IM 2018-014 affirms that the BLM lacks authority to require mitigation of surface disturbances on off-lease, non-federal lands. Second, IM 2018-014 identifies what materials the BLM will and will not require with applications for permits to drill (APDs) for horizontal wells drilled from off-lease pads sited on non-federal surface. For example, IM 2018-014 specifies that the BLM will not require surface use plans of operations or surface bonds with APDs. Finally, IM 2018-014 outlines the level of analysis that the BLM should perform under the National Environmental Policy Act, Endangered Species Act, and National Historic Preservation Act when approving wells drilled from off-lease pads sited on non-federal surface.

In the lawsuit, Western Watersheds Project challenges several directives in IM 2018-014. First, Western Watersheds Project objects to IM 2018-014’s assertion that BLM lacks authority to require mitigation of surface disturbances on off-lease, non-federal lands. Second, Western Watersheds Projects contests IM 2018-014’s directive that the BLM will not require surface use plans of operations for wells sited on off-lease, non-federal surface. Finally, Western Watersheds Project disputes IM 2018-014’s position that BLM will not require bonds to protect against surface impacts from wells sited on off-lease, non-federal surface and will not require reclamation of such surface impacts. Western Watersheds Project alleges that these directives conflict with the requirements of the Mineral Leasing Act of 1920, as amended, the Mineral Leasing Act for Acquired Lands, the Federal Land Policy and Management Act, and the BLM’s Onshore Order No. 1, and contradict BLM policies.

If successful, the lawsuit would upend BLM’s permitting of horizontal wells and add further delay to an already cumbersome federal permitting process. Western Watersheds Project has asked the court to declare IM 2018-014 unlawful and vacate it. This remedy could allow BLM to evaluate and require mitigation of surface impacts, including compensatory (i.e., offsite) mitigation, bonds, and surface use plans of operations associated with horizontal wells drilled from off-lease pads on non-federal surface.

Operators should monitor this lawsuit because of its potential to disrupt the BLM’s permitting processes. Operators should also communicate with local BLM offices to ensure that the BLM will not adjust its procedures in light of the pending lawsuit. If successful, the lawsuit could further burden development of federal oil and gas leases.

Last month, Governor Jared Polis signed two bills into law in response to growing public concern in Colorado and elsewhere regarding chemicals used in oil and gas operations, other industrial operations, and in consumer products, with a particular focus on a broadly defined group of perfluoroalkyl and polyfluoroalkyl compounds (“PFAS chemicals”).[1] On June 8, 2022, Governor Polis signed House Bill 22-1348, implementing disclosure requirements for any chemical that may be used in oil and gas production in Colorado, including PFAS chemicals, to encourage less-toxic alternatives and enable the public to evaluate the environmental and public health impacts of these chemicals. Earlier, on June 3, 2022, the Governor signed House Bill 22-1345, prohibiting the sale or distribution of consumer and industrial products, including fire-fighting foam, that contain intentionally added PFAS chemicals (“PFAS-containing products”).[2]

House Bill 22-1348

Oil and gas operators utilize chemical additives to facilitate drilling and extraction of oil and gas. The chemical compositions of these additives may not be easily ascertainable, in part due to trade secret protections. HB 22-1348 promotes transparency regarding chemical use in oil and gas production by requiring “Disclosers” (i.e., operators, service providers, and direct vendors of what are broadly defined as “chemical products” used in “downhole operations”) to:

1. disclose the chemical trade name of each product to the Colorado Oil and Gas Conservation Commission (the “Commission”);
2. disclose a list of the names and Chemical Abstracts Service Numbers of each chemical used in the product to the Commission; and
3. provide a written declaration to the Commission that the product contains no intentionally added PFAS chemicals.

If a Discloser is already selling, distributing, or utilizing a chemical product for downhole operations before July 31, 2023, the Discloser must complete the declaration and disclosures at least thirty days before July 31, 2023. If a Discloser begins to sell, distribute, or use such products on or after July 31, 2023, the declaration and disclosures must be completed at least thirty days before the Discloser begins selling, distributing, or using the product.

For oil and gas operations commenced before July 31, 2023, operators must provide the five disclosure requirements listed below to the Commission within 120 days after July 31, 2023. For oil and gas operations commenced on or after July 31, 2023, operators must submit the following disclosures to the Commission within 120 days after the commencement of downhole operations. The disclosure requirements include:

1. the date of commencement of downhole operations;
2. the county of the well site;
3. the API number and the U.S. well number assigned to the well;
4. the trade names and quantities of any chemical product; and
5. provide a written declaration that the chemical product contains no intentionally added PFAS chemicals.

If upon the request by a Discloser or the Commission, a manufacturer refuses to disclose this information due to trade secret protections, they must at the very least provide the Commission with the name and Chemical Abstracts Service Registry Numbers of each chemical used. The Commission may promulgate rules necessary for the implementation of these requirements.

HB 22-1348 also requires the Commission to create a public chemical disclosure list for each covered well site, including the names and Chemical Abstracts Service Registry Numbers of each chemical used in downhole operations. To protect trade secrets, the Commission is directed not to publish the trade name of a chemical product or the amount of a chemical used in a chemical product. On or before July 31, 2023, operators using a chemical disclosed on the Commission’s list must provide “Community notification” to a long list of public entities and private parties, that includes mineral and surface owners and occupants, land management agencies, local governments, nearby schools, and public water systems.

During committee testimony, Commission Director Julie Murphy expressed concerns with the bill’s “significant operational challenges” that may undermine the Commission’s mission, by draining time and resources from the many regulatory and administrative responsibilities that the Commission has undertaken under the Well Bore Integrity, Mission Change, and Financial Assurance Rulemakings. For the Commission, this may prove to be a substantial undertaking, which will duplicate, in part, the national, multi-million-dollar FracFocus database, which provides similar information for downhole chemicals used in hydraulic fracturing nationwide.[3] The current bill posits a modest $61,500 fiscal note for Colorado to implement the public disclosure list for all downhole chemical usage. See HB 22-1348 § 3(1).

In requiring a declaration that the downhole chemical product does not contain PFAS chemicals, Colorado is now, albeit through a disclosure requirement, effectively the first state to try to ban PFAS-containing products used for oil and gas development. However, the impact of this effort may be limited, if the American Petroleum Institute is correct that drillers in Colorado do not use PFAS chemicals during hydraulic fracturing operations.[4]

House Bill 22-1345

HB 22-1345 requires manufacturers and distributors to phase out the sale and distribution of certain PFAS-containing products in light of increasing concerns about possible adverse health effects associates with PFAS chemicals, even at very low concentrations.[5] While the bill is titled a “Consumer Protection Act,” the PFAS-containing products ban extends to “oil and gas products” and the statute also further regulates the use of PFAS-containing firefighting foam. The prohibition on use and sale extends to PFAS-containing products in the following categories on a phased schedule:

On or after January 1, 2024:

1. Carpets or rugs;
2. Fabric treatments;
3. Food packaging;
4. Juvenile products (i.e., cribs, floor play mats, infant seats, nursing pads, strollers); and
5. Oil and gas products (hydraulic fracturing fluids, drilling fluids and proppants).

On or after January 1, 2025:

1. Cosmetics;
2. Indoor textile furnishings; and
3. Indoor upholstered furniture.

On or after January 1, 2027:

1. Outdoor textile furnishings; and
2. Outdoor upholstered furniture.

Additionally, cookware containing intentionally added PFAS chemicals must contain a consumer warning label and provide information about why the PFAS chemicals are present in the cookware.

Manufacturers of consumer products have been phasing out their reliance on PFAS chemicals for some time now given the health and environmental concerns associated with these chemicals. The outdoor recreation industry, which is so important to Colorado’s economy, was one of the first industries to pivot to new alternatives for PFAS’s repellent and retardant properties. Many brands, including Fjällräven and Keen, have already successfully phased out PFAS-containing products. Other brands are following suit, including Patagonia and The North Face, which both recently made public commitments to eliminate PFAS-containing products over the next few years. So, the actual impact on Colorado manufacturer and distributor operations could be limited. The fact that the statute posits an outright prohibition on the sale of certain products and is not just a notice statute, would seem to raise constitutional concerns under both the Commerce Clause and federal preemption. But that has not stopped other states, including California, Maine, Massachusetts, and a few others, from enacting similar statutes.[6]

Meanwhile, businesses should carefully evaluate any new restrictions or disclosure requirements associated with these statutes. Businesses and activities that emit or discharge PFAS chemicals into the environment, or whose other wastes contain PFAS chemicals (e.g., wastewater treatment sludge), are also likely to see stringent and costly control requirements in the near future and should plan accordingly. Also, if as currently planned, and certain PFAS chemicals get listed as CERCLA “hazardous substances,” any number of Superfund sites may need to be reopened and extensive litigation to redistribute at least some of the cost of expensive remediation requirements is likely.

[1] “PFAS chemicals” is defined as a class of fluorinated organic chemicals containing at least one fully fluorinated carbon atom. C.R.S. § 25-5-1302(7).
[2] For prior legislative action on firefighting foams see: C.R.S. §§ 25-5-1301 – 1308, §§ 24-33.5-1234(4), (5), (6), §§ 8-20-206.5(6), (7).
[3] Scott Weiser, “Polis signs new law mandating disclosure of fracking chemicals,” (June 2022).
[4] Id.
[5] On June 15, 2022, the EPA released four drinking water health advisories for PFAS chemicals at very low levels, including 0.004 parts per trillion (ppt) for PFOA. See Lifetime Drinking Water Health Advisories for Four Perfluoroalkyl Substances, 87 Fed. Reg. 36,848 (June 21, 2022).
[6] See Product safety: textile articles: perfluoroalkyl and polyfluoroalkyl substances (PFAS), AB-2827, Cal. Leg., 2021-2022 Regular Session; An Act to Stop Perfluoroalkyl and Polyfluoroalkyl Substances Pollution, LD 1503, 130th Maine Leg. (2021); An Act Restricting Toxic PFAS Chemicals in Consumer Products to Protect Our Health, H 4818, Mass. Leg. 192nd Session (2022).

In Parts I and II of this series, we discussed EPA’s “Climate Resilience” and “Greener Cleanups” initiatives, programs aimed at improving the sustainability of remedial activities at Superfund sites in response to climate change. In this final installment, we discuss the growing role for “environmental justice” (“EJ”) in CERCLA decision-making and highlight opportunities to leverage EJ considerations to achieve better outcomes for both disadvantaged communities and PRPs.

EPA defines “environmental justice” as “the fair treatment and meaningful involvement of all people regardless of race, color, national origin, or income, with respect to the development, implementation, and enforcement of environmental laws, regulations, and policies.” EJ is not a new concept, but President Biden seeks to make it a cornerstone of his Administration’s environmental policy. Since January 2021, the President has issued multiple Executive Orders aimed at promoting EJ initiatives, including Executive Order 13985, “Advancing Racial Equity and Support Through the Federal Government,” dated January 20, 2021. See also Executive Order 13990, “Protecting Public Health and the Environment and Restoring Science To Tackle the Climate Crisis” (Jan. 20, 2021); Executive Order 14008, “Tackling the Climate Crisis at Home and Abroad” (Jan. 27, 2021). The Administration’s emphasis on environmental justice also is reflected in EPA’s Strategic Plan
for fiscal years 2022-2026 and EPA’s Draft EJ Action Plan, both published earlier this year.

Against this backdrop, EPA has taken a number of steps to integrate EJ goals into the Superfund program. In July 2021, EPA issued a memorandum directing the Regions to strengthen enforcement of CERCLA by prioritizing “early action and/or enforcement efforts on Superfund site operable units that most impact overburdened communities.” See Memorandum: Strengthening Environmental Justice Through Cleanup Enforcement Actions, from Larry Starfield, Acting Assistant Administrator, to Regional Superfund Division Directors and Deputies, et al.
(July 1, 2021), at 2. EPA also issued a revised model RD/RA Consent Decree and Statement of Work in August 2021. Section 2 of the new model Statement of Work imposes expanded community involvement requirements on Settling Defendants. Finally, in its Draft EJ Action Plan, the Agency proposed to develop (1) guidance directing regional offices to consider and document EJ information during remedy selection, and (2) recommendations for expanding “emphasis on equitable redevelopment and community-wide revitalization during Superfund Redevelopment work with communities.” U.S. EPA, Draft EJ Action Plan, EPA 502/P-21/001 (Jan. 5, 2022), at 22-23.

EPA has also targeted funding from the November 2021 Bipartisan Infrastructure Law (“BIL”) to advance EPA’s EJ objectives for the Superfund program. Under the BIL, Congress earmarked $3.5 billion for the program, and EPA announced late last year that it would use the first $1 billion to clear its backlog of projects at 49 previously unfunded Superfund sites. According to the Agency, more than 60% of the sites are located in historically underserved communities.[1]

New state laws are influencing EPA’s implementation of EJ, too, and they provide a glimpse into where stakeholders can expect more regulatory activity. For example, in July 2021, Colorado enacted the Environmental Justice Act, HB 21-1266, which established criteria for identifying “disproportionately impacted communities” and prioritized outreach and state action to reduce environmental health disparities in those communities. The Act defines a “disproportionately impacted community” as, among other things, a community in a census block group where:

• the proportion of households that are low income is greater than 40%;
• the proportion of households that identify as minority is greater than 40%; or
• the proportion of households that are housing cost-burdened is greater than 40%

See § 24-4-109(2)(b)(II), C.R.S. In March 2022, EPA Region 8 entered into a Memorandum of Understanding with the Colorado Department of Public Health and Environment to initiate a partnership and expand collaboration between the two agencies to strategically target environmental compliance inspections and enforcement actions in disproportionately impacted communities.

No federal law currently mandates consideration of environmental justice in the Superfund decision-making process, and EPA has not yet issued guidance on its EJ goals and considerations in remedy selection and five-year reviews. But EJ considerations are already relevant to remedy selection—“community acceptance” is one of the nine NCP criteria for evaluating remedial alternatives, and the NCP contemplates soliciting comments regarding the community’s position on alternatives. See 40 C.F.R. § 300.430(e)(9)(I). As for five-year reviews, we anticipate additional directives from EPA aimed at upgrading and expanding opportunities for community engagement.

The Administration’s EJ policies raise fundamental questions for the Superfund program, including what role communities should play in defining cleanup objectives for remedy selection. Many disproportionately impacted communities have faced historical underinvestment and underdevelopment. Contaminated properties present opportunities to begin alleviating historical inequities by developing otherwise unusable land to support the jobs, infrastructure, and open-space amenities these underserved communities clearly need to support residents and flourish. However, unattainable cleanup objectives—and the overengineered remedies implemented to try to reach them—lock up these properties and stymie development.

In May 2021, the National Environmental Justice Advisory Council, an advisory council to EPA, published a report recommending that EPA elevate communities’ needs and desired future uses in the Superfund decision-making process. See Superfund Remediation and Redevelopment for Environmental Justice Communities, NEJAC (May 6, 2021), at 12. The report reflects an obvious truth: Communities should be involved in determining cleanup objectives and remedial actions with an eye toward returning properties to the beneficial uses they believe they need.

There is real opportunity here for PRPs. Community engagement can help identify appropriate future uses of properties that are not tied to unattainable cleanup objectives and overengineered remedies that have plagued so many Superfund sites over time. In Jersey City, New Jersey, for example, a Superfund landfill site currently is being transformed into a much-needed community park and river access. See
Marilyn Baer, “From toxic site to Jersey City park,” Hudson Reporter (Dec. 3, 2020). The Whitmoyer Laboratories Superfund Site in Pennsylvania is now home to several recreational facilities. See EPA Superfund Redevelopment Initiative, Recreational Reuse and the Benefit to the Community (Oct. 2020). Focusing on and leveraging community needs to support more practical cleanup objectives and remedies that actually achieve those objectives has obvious potential benefits for PRPs and local communities alike.

The Superfund program continues to change and mature. This series explored three initiatives—“Climate Resilience,” “Greener Cleanups,” and environmental justice—that are beginning to transform the Superfund decision-making process. From the rising frequency of extreme weather events to equity concerns in underserved communities, EPA must wrestle with how to achieve cleanup objectives while ensuring a more sustainable future for all. That leaves room for the regulated community to invoke sustainability goals to support community outreach and the selection of more sensible remedies to improve outcomes at Superfund sites, whether in remote landscapes or dense urban centers.

[1]
Relevant to Parts I and II of this series, Congress also earmarked funds for projects related to climate resilience and clean energy, including $1.5 billion for wildfire resilience investments and $20 billion for clean energy demonstration projects.

The new Denver “Expanding Housing Affordability” Ordinance amends Ch. 27 of the Denver Revised Municipal Code by: (1) revising provisions related to the linkage fee; (2) implementing incentives for developing affordable housing; and (3) adopting affordable housing requirements applicable to the creation of new dwelling units. The new policy will take effect in Denver starting July 1, 2022. In summary, the new ordinance:

1. Requires all new residential development of 10 units or more to designate 8% to 12% of the units as affordable for a period of 99 years, regardless of whether the home is for rent or for sale. To align with state law, which requires alternatives to this requirement, the new policy includes the following options in lieu of allocating affordable housing units:
   1. An option to pay a fee-in-lieu of the affordable units. This fee ranges from $250,000 to $478,000 depending on the unit type and market area and will be calculated pursuant to the table attached hereto as Exhibit “A”.
   2. Negotiated and community-driven housing agreements in certain situations that allow for flexibility and benefit the community in alignment with city housing goals, which include the following:
      1. The dedication of land for the provision of affordable housing.
      2. An affordable housing plan to provide fewer IRUs on-site but at a greater depth of affordability.
      3. An affordable housing plan that would provide fewer IRUs on-site but the IRUs would have a greater number of bedrooms than would otherwise be required.
      4. An agreement to provide off-site IRUs concurrently with the construction of the residential development within the same statistical neighborhood or a 1/4 mile radius of the site.
2. Increases the “linkage fee” assessed on development which does not incorporate IRUs over a period of five years. The linkage fee is imposed prior to the issuance of a building permit for any new structure or for any addition to an existing structure that increases the gross floor area of the existing structure according to the schedule attached hereto as Exhibit “A”.
3. Offers zoning and financial incentives, such as flexible parking requirements, height incentives, and permit fee reductions, to offset the cost of building affordable units and increase the overall supply of housing.
   1. Permit Fee Reduction. An applicant will receive a building permit fee reduction of six thousand five hundred dollars ($6,500.00.00) per IRU in a typical market area and ten thousand dollars ($10,000.00) per IRU in a high market area. The building permit fee reduction shall not exceed fifty percent (50%) of the total building permit fee.
   2. Reduced minimum vehicle parking required by the Denver Zoning Code. An applicant may utilize the alternative minimum vehicle parking ratios allowed in Article 10 of the Denver Zoning Code.
   3. Commercial, sales service and repair street level exemption to linkage fee. An applicant may receive an exemption from the requirement to pay a linkage fee for the gross floor area of a primary commercial sales, services, and repair use located on the street level of a structure

Additional resources and further details can be found on the project webpage: www.denvergov.org/affordabilityincentive.