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.

Colorado recently passed a new bill which is expected to be signed by Governor Polis. The bill makes significant changes to Colorado statute 8-2-113 regarding non-compete agreements. This bill has also added some additional limits on confidentiality agreements as well as non-solicitation agreements. It has provided new penalty and enforcement mechanisms. These changes are going to significantly affect Colorado law in this area.

As you know, Colorado statute provides that non-competes are void in Colorado unless the non-compete falls into one of the statutory exemptions. Those exemptions were non-compete agreements in connection with the sale or purchase of a business; non-competition agreements for the protection of trade secrets; contractual provisions governing recovery of training or education expenses for an employee who has stayed for less than two years and covenants relating to employees who are management or executive employees.

The new statute keeps the exemption for covenants in connection with the sale of a business, but eliminates the exemption for management and executive employees. It imposes a minimum salary threshold of $101,250.00 per year in 2022 or an annualized amount of that salary if the employee is employed for less than the full year. For employees who meet the highly compensated salary requirements, if the non-compete is for the protection of trade secrets and the covenant is no broader than reasonably necessary to protect the employer’s legitimate interest in protecting trade secrets, the covenant may be allowable.

The new bill allows a covenant not to solicit customers for employees who earn at least 60% of the highly compensated threshold amount. That non-solicitation covenant can be no broader than necessary to protect the employer’s legitimate interest in protecting trade secrets. Currently that means that employees who earn at least $60,750.00 annually can be subject to appropriately narrow non-solicitation agreements.

The bill does allow for the recovery of education and training expenses over the course of two years although it narrows the definition of training to exclude on the job training.

The bill adds confidentiality agreements to the statute. Previously Colorado did not limit the use of confidentiality agreements as long as it did not attempt to protect information that was in the public. The confidentiality agreement must not prohibit disclosure of information that arises from the worker’s general training, knowledge, skill or experience, whether gained on the job or otherwise, information that is readily ascertainable to the public or information that the worker has a right to disclose as legally protected conduct.

The bill also allows for recovery of scholarship provided to an individual working in an apprenticeship if the individual fails to comply with the conditions of the scholarship agreement.

The bill also states that even if otherwise acceptable, the covenant will be void if the employer does not provide notice of the terms of the non-compete to a prospective worker before the worker accepts the offer of employment or to a current worker at least fourteen days before the earlier of the effective date of the covenant or the effective date of any additional compensation or change in the terms and conditions of employment that provides consideration for the covenant.

The notice must be separate from any other covenants and in clear and conspicuous language. It must also be signed by the worker. There are additional requirements in the statute for how the notice must be given. It is important to note that the notice must contain language notifying the worker that the covenant may restrict their options for subsequent employment and specifically identifies there those restrictions are.

Non-competes for physicians are also void, although the statute continues to allow damages to be recovered related to competition.

This law applies to all workers who at the time of termination primarily resided or worked in Colorado. It prohibits employers from requiring the worker to adjudicate the enforceability of the covenant outside of Colorado.

Enforcement of this statute is also expanded. Any person who uses force, threats, or other means of intimidation to prevent a worker from engaging in any lawful occupation commits a misdemeanor under this statute. An employer can be liable for actual damages and a penalty of $5,000 dollars for a worker harmed by this conduct and get injunctive relief. The statute also provides that a worker or prospective worker can recover actual damages, reasonable costs, and attorney’s fees in any action under this section.

If an employer’s act or omission was in good faith and the employer had reasonable grounds for believing that the act or omission was not a violation of this section a court may elect to not award a penalty.

This statute is expected to be effective August 10, 2022 and will apply to all covenants not to compete entered into or renewed on or after the effective date of this statute.

Practice Pointers:

• Review all non-competition agreements to determine if they comply with this statute
• Review all non-solicitation agreements to determine if they comply with this statute
• Review all confidentiality agreements to determine if they contain the language reflected in the statute
• Before asking any prospective or current employees to sign a non-compete, consult with counsel.

Before seeking to enforce any non-compete, consult with counsel.

As this newsletter goes to print, the Colorado Public Utilities Commission will have just concluded a further evidentiary hearing in the matter of the Application of Public Service Company of Colorado for approval of its 2021 electric resource plan and clean energy plan in proceeding No. 21A-0141E. The Application was filed on March 31, 2021, and is Colorado’s first clean energy plan proceeding under Senate Bill 19-236. The Senate Bill required Public Service to include in its next electric resource plan (i.e., its 2021 plan) a clean energy plan to reduce its carbon dioxide emissions associated with electricity sales by 80% (from 2005 levels) by 2030 and to seek to achieve providing customers with energy generated from 100% clean energy resources by 2050.

The clean energy plan was required to include a resource acquisition period extending through 2030 and to set forth a plan of actions and investments by Public Service projected to achieve compliance with the 80% requirement and 100% goal. If the clean energy plan included accelerated retirement of existing facilities, it also had to include a workforce transition plan and a community assistance plan to address the local jobs and property tax impacts of the plan.

The application included eight portfolios of wind, solar, and dispatchable generation resources that met or exceeded the 80% requirement but with different cost impacts. The term “dispatchable” means a resource that Public Service can ramp up and down to meet operating conditions (with quick start capability of 10 minutes or less and capability to be remotely started by Public Service at any time). The dispatchable resources that are expected to be acquired are natural gas-fired electric generating resources and battery storage.

The eight portfolios varied depending upon the actions Public Service took with regard to its Pawnee and Comanche 3 coal-fired power plants. The range of actions included converting to natural gas, early retirement in various years, or business as usual. All other existing Public Service coal-fired power plants are proposed for early retirement prior to 2030 to help achieve the greenhouse gas reduction requirement of the statute.

Public Service’s preferred portfolio was number 7, which involved converting the Pawnee power plant to natural gas in 2027 and retiring the Comanche 3 coal power plant early (in 2039) but reducing its operations to 30% starting in 2030. As a result of these actions and Public Service’s estimate of its resulting resource needs, the preferred plan proposed the following acquisitions during the resource acquisition period:

• 2,300 MW of wind
• 1,800 MW of large-scale solar
• 400 MW of battery storage
• 1,300 MW of flexible dispatchable generation (this is 100 MW less than Public Service has today)

All eight portfolios were based upon generic modeling results. Following the Commission’s final decision in the pending proceeding, there will be a Phase II all-source competitive solicitation which can change the type and amounts of additional resources that are added.

Following interventions, discovery, and several rounds of filing of testimony by the parties, the application was scheduled to proceed to hearing. But Public Service and the parties were also engaged in confidential settlement negotiations to see if they could settle some of the key issues that had been identified in the proceeding. On November 24, 2021, a Joint Motion was filed requesting approval of a Non-Unanimous Partial Settlement Agreement. The Agreement addressed major issues in the proceeding including moving up the retirement date for Comanche 3 by five years (to the end of 2034), providing for a just transitions plan to address the loss of jobs and tax impacts of the early retirement on the Pueblo community in which Comanche 3 is located, and numerous other issues. The Settlement Agreement was a modification to the Application (including Public Service’s preferred portfolio 7) as to the issues addressed in the Settlement Agreement. Oppositions to the Agreement were also filed.

An evidentiary hearing was held during the first two weeks of December and then the evidentiary record was closed. (Public comments have been filed throughout the proceeding and continued to be filed with the Commission.) The parties filed Statements of Position in January of this year and then the application was ready for Commission decision. The Commission held its first deliberations meeting on March 14, 2022, at which the Commissioners discussed but did not decide several of the major issues in the proceeding.

Following the initial meeting, the Settling and Non-Settling Parties convened discussions regarding potential resolution of key items in a manner response to the Commission discussions on March 14, 2022. The objective of these further discussions was to resolve items and avoid the potential for a protracted reconsideration, reargument, or rehearing process that could further delay the commencement of the Phase II competitive solicitation. Avoiding such delay is critical so that bidders can qualify for available tax credits for their projects. The result of these further discussions was the filing on April 26, 2022, of an Updated Non-Unanimous Partial Settlement Agreement. This Updated Settlement Agreement was the subject of the further evidentiary hearing, which was held on May 17, 2022.

The current proposal, as presented in the Updated Settlement Agreement, includes the following terms:

• Retirement date for the Comanche 3 coal plant. Moves the retirement date for Comanche 3 from no later than December 31, 2034, to no later than January 1, 2031. Provides for reduction targets in operation of Comanche 3 by increasing amounts through 2029.
• Pawnee coal plant. Provides for conversion of Pawnee to natural gas no later than January 1, 2026.
• Other coal plants. Provides for retirement of Hayden 2 in 2027, Hayden 1 in 2028, and Craig 2 in 2028.
• Just Transition Plan for Pueblo County – Location of Comanche 3. Proposes that:
• Public Service will continue to make payments to Pueblo County annually from 2031 through 2040 (and allocated by the treasurer’s office accordingly) in the amount of the projected lost property tax revenues for those years, unless offset by property tax revenues from generation or transmission infrastructure sited at Comanche Station or within Pueblo County.
• A separate Comanche 3 Just Transition Plan to be filed with the Commission no later than June 1, 2024. Through its Just Transition Plan filing for Comanche 3, the Company will conduct a standalone Just Transition Plan competitive solicitation for the replacement of the energy and capacity associated with Comanche 3. This process will occur on a standalone basis in an effort to ensure the Pueblo community and benefits to the community are the focus of the replacement portfolio, simultaneously seeking just transition benefits and the procurement of innovative technologies to help the Company progress towards a carbon-free future.
• Public Service will own, at a minimum, $690 million in capital investment or 500 MW of accredited capacity, whichever is triggered first, for resources necessary to replace the accredited capacity of Comanche 3, provided that a showing of resource need is made in the first phase of the Comanche 3 Just Transition Plan filing and any final approved plan in the second phase must be deemed a cost-effective resource plan consistent with Rule 3601 and Rule 3617 after a full consideration of the just transition and emissions reduction benefits of the plan.
• The Just Transition Plan solicitation will also utilize a utility ownership target of 50 percent for energy and capacity acquired that is in excess of the $690 million investment or 500 MW accredited capacity minimum, and provided that the final approved resource plan is cost-effective as set forth above.
• Provides for a process where generic resources will fill the Company’s Phase II resource needs in 2029 and 2030 while having the 2029 and 2030 resource needs filled through the Pueblo Just Transition Plan solicitation as opposed to this 2021 ERP & CEP.
• Next electric resource plan.
  Establishes that the Company will file its next Electric Resource Plan no later than October 31, 2026.

Modeling results (based upon generic resources) indicate that the Updated Settlement Agreement will reduce carbon emission from 2005 levels by 85% by 2030 and by 99% by 2050.

The modeling also shows the following resource acquisitions through 2030:

But, as noted above, the resource needs in 2029 and 2030 will not be filled through the upcoming Phase II competitive solicitation. Generic resources will be used for 2029 and 2030 in the modeling of the Phase II bids. The 2029 and 2030 resource needs will be filled through the Pueblo Just Transition Plan competitive solicitation.

The next step in the proceeding is for the Commission to deliberate in one or more open meetings, which can be viewed through the Commission’s webcast. Go to: https://puc.colorado.gov/webcasts The Commission will be deliberating regarding the proposed Modified Settlement Agreement and all issues raised in the proceeding that were not included in the Modified Settlement Agreement. (A list of the unsettled issue was filed with the Commission following the May 17, 2022, hearing.) Once the Commission has deliberated on and decided all issues, an initial written decision will be written and signed by the Commissioners. Parties in the proceeding will then have 20 days after the mailing date of the Commission decision (as printed on page one of the Decision) within which to request rehearing, reargument, or reconsideration (“RRR”). If no requests for RRR are filed within the 20-day time period, then the Commission’s decision becomes the final decision of the Commission. If the Commission does not act upon an application for RRR within 30 days of its filing, the application is denied and the Commission’s initial decision is final. If one or more requests for RRR are filed and the Commission elects to act on them, then the initial decision, as modified by the Commission’s decision on RRR, becomes the final decision of the Commission. See Commission Rule 1506. A Final Commission Decision may be appealed to state district court. § 40-6-115, C.R.S.

Once there is a final Commission Decision, the next step will be for Public Service to make any modifications required by the Commission’s Decision and get set up to conduct an all source competitive solicitation to fill the resource need approved in the Commission’s Decision. Once the request for proposals (“RFP”) is issued, bidders will have 90 days within which to submit their bids in accordance with the detailed instructions in the RFP bid package.

A Commission initial Decision is expected in early summer.

On December 27, 2021, the U.S. Army Corps of Engineers (“Corps”) issued a final rule regarding its Nationwide Permits (“NWPs”) for dredge and fill activities (“December 2021 Rule”). See 86 Fed. Reg. 73522 (Dec. 27, 2021). The December 2021 Rule reissued 40 NWPs and issued one new NWP. The Rule also retained consequential changes made to 16 other NWPs in January 2021 and incorporated some of those changes into the newly reissued permits. Most significantly, the December 2021 Rule retained and extended to all NWPs a stringent new mitigation condition adopted in January 2021. The new and revised NWPs took effect on February 25, 2022.

In addition, as of late May 2022, a lawsuit is pending in Montana challenging and attempting to rescind NWP 12 for oil and gas pipelines. The Corps has also undertaken a formal review of that NWP, after seeking public comment about whether NWP 12 should be made more limited or restrictive. Entities seeking to use these revised or challenged NWPs should carefully review the pertinent revisions and stay apprised of the pending challenges and ongoing agency review of NWP 12.

Background on the Corps’ Nationwide Permit Program

The Corps regulates dredge and fill activities (e.g., stream crossings and wetland fills) under Section 404 of the Clean Water Act (“CWA”), 33 U.S.C. § 1344, and Section 10 of the Rivers and Harbors Act, 33 U.S.C. § 403. In lieu of requiring individual permits for every regulated activity, the CWA authorizes the Corps to issue “general” permits, including NWPs, for categories of activities that “are similar in nature, will cause only minimal adverse environmental effects when performed separately, and will have only minimal cumulative adverse effect on the environment.” 33 U.S.C. § 1344(e)(1). Project proponents commonly rely on NWPs for earth-moving activities associated with real estate development, mining, oil and gas activities, water, transportation, and energy facilities, and related maintenance and repair operations. The Corps’ website has a useful summary of the 57 current NWPs, including changes from the last two rulemakings.

Many renewable energy facilities and other sustainability projects benefit from the Corps’ NWP Program. For example, the Corps has issued NWPs for land-based renewable energy generation facilities (NWP 51) and water-based renewable energy generation pilot projects, like offshore wind farms (NWP 52). As discussed below, the Corps recently issued a new NWP for water reclamation and reuse facilities (NWP 59), such as wastewater treatment plants that produce treated effluent for reuse applications like irrigation. And, of course, all these types of projects also benefit from more general NWPs, like NWP 3 (for maintenance activities), NWP 57 (for electric utility and telecom lines), and NWP 58 (for other types of non-oil and gas utility lines).

NWPs greatly reduce—but do not eliminate—the complexities of dredge and fill permitting. Some NWPs require project proponents to provide the Corps with pre-construction notification (“PCN”), which allows the Corps to evaluate NWP-eligible projects on a case-by-case basis. PCN requirements vary by NWP and project type. For example, under NWP 51, proponents of land-based renewable energy generation facilities must submit a PCN if the proposed activity will result in the loss of more than 0.10 acres of waters in the United States. In contrast, under NWP 44, all mining activities are subject to PCN.

The Corps imposes terms and conditions for projects through conditions in each NWP and in the Nationwide Permit General Conditions. For example, under General Condition 23 as revised in 2021 (see below), the Corps requires compensatory mitigation at a minimum one-to-one ratio for projects that require PCN and will result in the loss of more than 0.10 acres of wetland or more than 0.03 acres of stream bed. Each District Office may impose additional or amended conditions for the use of NWPs within its district, including project-specific conditions and region-wide PCN requirements that do not appear on the face of the NWPs. See 33 C.F.R. § 330.4(e)(1), (2). Each state also may impose additional restrictions or conditions on certain NWPs (when used within such state) through CWA Section 401 certification of the new or newly reissued NWPs. Section 401 certification nominally must occur within one year of issuance of the NWPs.

The Corps Addressed 16 NWPs in a Final Rule Issued in Early 2021

Under the CWA, the Corps may issue an NWP or other regional or statewide general permit for only five years, requiring periodic reissuance. Prior to December 2021, the Corps last issued new and revised NWPs just 11 months earlier, in January 2021. See 86 Fed. Reg. 2744 (January 13, 2021) (“January 2021 Rule”). However, the January 2021 Rule only applied to 16 NWPs. This resulted in two groups of NWPs subject to two different expiration dates—those issued or reissued in January 2021 (set to expire on March 14, 2026) and those last issued or revised in January 2017 (set to expire on March 18, 2022), see 82 Fed. Reg. 1860.

The January 2021 Rule complicated the NWP program in two other ways. First, the Corps issued revised NWP General Conditions that applied only to the 16 NWPs addressed by that Rule. Notably, the Corps set a 0.03-acre threshold for the amount of stream-bed loss that triggers required compensatory mitigation and made that mitigation requirement applicable to all 16 NWPs if and when they require PCN. Id. at 2871.

Second, due to long-pending controversies over the use of NWP 12 for extensive oil and gas pipelines, the Rule separated linear transmission projects into three categories subject to separate NWPs. NWP 12—which previously covered linear transmission projects generally—was revised to apply only to construction, maintenance, repair, and removal of oil and natural gas pipelines and associated activities. Id. at 2769. Two new NWPs were issued to cover electric and telecommunication projects (NWP 57) and water and any other utility line projects (NWP 58).

The Corps Declined to Revisit the January 2021 Rule in Its Recent Final Rule

The Corps issued another final rule in December 2021. Given that the January 2021 Rule was issued in the last days of the Trump Administration, some commentators expected the Corps to walk back changes to the NWPs, including the more lenient standards imposed on oil and gas pipeline projects under NWP 12. However, the Corps declined to revisit the NWPs and conditions issued or revised in January 2021, instead opting to restore some consistency across the NWP program. See 86 Fed. Reg. 73522, 73525.

Five
important takeaways from the December 2021 Rule are as follows:

1. The General Conditions issued or revised in January 2021 now apply to all NWPs. See 86 Fed. Reg. 73522, 73525. Most importantly, all 57 NWPs are now subject to a uniform General Condition 23, requiring at least one-to-one compensatory mitigation for any project that requires PCN and will cause the loss of more than 0.03 acres of stream bed. This is an extremely low threshold. Because streams are considered “difficult-to-replace resources,” the Corps encourages permittees to implement stream rehabilitation, enhancement, or preservation to accomplish compensatory mitigation; however, permittees also may accomplish mitigation through restoration or enhancement of riparian areas. See 86 Fed. Reg. 2744, 2871; see also 33 C.F.R. § 332.3(e)(3). Potential NWP permittees should carefully consider whether their project will trigger this mitigation requirement and, if so, determine in advance how, where, and when the requirement can be satisfied. This determination may call for pre-construction conferral with the Corps.
2. The Corps did not reconsolidate NWPs 12, 57, and 58, and will continue to authorize dredge and fill activities associated with eligible oil and gas pipeline projects only under NWP 12 or individual Section 404 permits. Proponents of other linear transmission projects seeking to use an NWP must still seek authorization under the two distinct permits issued early last year, NWP 57 (electric utility line and telecommunication activities) and NWP 58 (utility line activities for water and other substances).
3. The Corps reissued 40 NWPs but only amended the text of a few of them. The textual changes made in the December 2021 Rule were minor. For example, the Corps added “driveways” to the list of linear transportation projects covered by NWP 14. 86 Fed. Reg. 73522, 72535, 73574. The January 2021 Rule, on the other hand, implemented more consequential changes to the NWPs, such as eliminating provisions that used to disqualify projects from NWP authorization if they would cause the loss of more than 300 linear feet of stream bed. See 86 Fed. Reg. 2744, 2785.
4. The Corps issued one new permit, NWP 59, which authorizes discharges of dredged or fill material from the construction, expansion, and maintenance of water reclamation and reuse facilities. See 86 Fed. Reg. 73522, 73558. The Corps recognized the importance of such facilities for climate change adaptation, including both potable and non-potable reuse applications.
5. All existing NWPs now expire on the same date, March 14, 2026.

To some extent, the December 2021 Rule reduces the complexity and uncertainty injected into the NWP program by the January 2021 Rule—the regulated community can again look to a single set of NWPs, with uniform General Conditions and expiration dates. That said, the December 2021 Rule could greatly expand the number of projects that need to conduct compensatory mitigation by extending the expanded General Condition 23 to all 57 NWPs.

Prospective NWP permittees also should be on the lookout for any regional NWP conditions added or amended by the Corps’ District Offices, as well as any state-specific conditions added by states through their CWA Section 401 certification of the NWPs. Permittees should pay special attention to any new PCN requirements added by those supplemental conditions, which could trigger General Condition 23’s stringent mitigation requirement for NWPs that do not on their face require PCN.

The Corps’ December 2021 Rule Is Not the Final Word on NWP 12

Although the Corps declined to reconsolidate or otherwise revise NWPs 12, 57, and 58, controversy remains over the provisions of NWP 12. In May 2021, environmental organizations, including the Center for Biological Diversity and Sierra Club, sued the Corps in the District of Montana. See Center for Biological Diversity, et al. v. Spellmon, et al., No. 4:21-cv-47-BMM (D. Mont. May 3, 2021). The plaintiffs contend that reissuance of NWP 12 violated the Endangered Species Act, National Environmental Policy Act, and Clean Water Act, and they ask the court to vacate the permit. As of late May 2022, cross-motions for summary judgment are pending before Chief Judge Brian Morris.

Spellmon illustrates some of the tensions inherent in the clean energy transition. The plaintiffs take issue with the streamlined permitting afforded to oil and gas pipeline projects under NWP 12, but their arguments are not entirely unique to oil and gas issues. In an amicus brief filed on April 1, 2022, the Edison Electric Institute argued that the plaintiffs’ claims under the ESA, NEPA, and CWA threaten to undermine the entire NWP Program—and hence, the streamlined permitting process upon which renewable energy and other sustainability projects have come to rely. The U.S. Chamber of Commerce raised a similar concern in its amicus brief.

Amidst the flurry of briefing in Spellmon, the Corps published a notice of its intent to conduct a formal review of NWP 12. See 87 Fed. Reg. 17281 (Mar. 28, 2022). In the Corps’ view, “[p]revious uses of NWP 12 have raised concerns identified in Executive Order 13990, such as environmental justice, climate change impacts, drinking water impacts, and notice to impacted communities.” Id. at 17282. As part of its review, the Corps held public meetings throughout May 2022 and solicited public comment on a variety of topics, including whether further limits on NWP 12 or changes to the NWP General Conditions would be prudent. Id. at 17283. The Corps’ review will likely track President Biden’s emphasis on progressive environmental policies like environmental justice and climate change mitigation. However, further changes to the NWP General Conditions could have unintended impacts on sustainability projects, which already face more onerous mitigation requirements following the December 2021 Rule.

Entities seeking to use any NWPs should carefully review and comply with the pertinent changes to those NWPs and should also closely follow the pending challenges and ongoing agency review of NWP 12, which may very well have ramifications for the entire NWP Program.

The Colorado General Assembly wrapped up its 2022 legislative session on May 11, 2022. In our February newsletter, we provided an overview of energy-related bills as of February 8, 2022. At that time, only a handful of energy-related bills had been proposed. But by the end of the session, the legislature considered almost 20 bills related to energy, environmental protection, and air quality. This update highlights some of the final bills that were passed and some that were not.

Energy-Related Bills That Passed

Many of the bills passed this session are aimed at furthering clean energy development in Colorado. Here are some of the highlights:

• House Bill 22-1381, Colorado Energy Office Geothermal Energy Grant Program: This bill creates a geothermal energy grant program to facilitate the development of geothermal heating systems and geothermal electricity generation.
• Senate Bill 22-118, Encourage Geothermal Energy Use: This bipartisan bill seeks to encourage the use of geothermal energy by providing regulatory treatment similar to that afforded solar energy. Among other provisions, the bill requires the Colorado energy office to develop basic consumer education and guidance about leased or purchased geothermal installation, in consultation with industries that offer these options to consumers.
• Senate Bill 22-110, Equip Wind Turbine Aircraft Detection Lighting System: This bill requires an owner or operator of certain wind-powered energy generation facilities to equip them with an aircraft detection lighting system.
• House Bill 22-1362, Building Greenhouse Gas Emissions: This bill updates the state’s minimum energy code requirements. Among other things, the bill requires the creation of the building electrification for public buildings grant program, creating the high-efficiency electric heating and appliances grant program, and establishing the clean air building investments fund.
• House Bill 22-1355, Producer Responsibility Program For Recycling: This bill requires companies that sell consumer-facing packaging to join a producer responsibility organization, which in turn would charge fees to fund a statewide recycling system.

Energy-Related Bills That Failed

One of the more prominent energy-related bills to fail in the 2022 legislative session was Senate Bill 22-138, titled Reduce Greenhouse Gas Emissions In Colorado. This bill concerned measures to promote reductions in greenhouse gas emissions by, among other things, incentivizing people to buy electric lawn equipment. It also included measures directed at streamlining carbon capture and sequestration projects in Colorado, including giving the Colorado Oil and Gas Conservation Commission authority to issue and enforce Class VI injection wells used for sequestration of greenhouse gases.

In addition, two of the bills mentioned in our February 2022 newsletter were ultimately rejected by the legislature. Senate Bill 22-073, titled Alternative Energy Sources, would have directed the state to investigate the feasibility of using small modular nuclear reactors as a carbon-free energy source for Colorado. That bill was sent to the State, Veterans, and Military Affairs Committee, where it ultimately died. House Bill 1140, titled Green Hydrogen To Meet Pollution Reduction Goals, would have directed the state to recognize green hydrogen as a renewable energy source that certain retail electric service providers could use to meet statewide greenhouse gas pollution reduction goals. That bill was ultimately killed in the House Energy and Environment Committee.

What Should We Expect from the 2023 Legislative Session?

It’s too soon to say. But at the end of this session, none of the bills proposed addressed pore space ownership. As we noted in our February 2022 newsletter, ownership of the pore space remains unresolved in Colorado, and obtaining certainty about who owns the pore space is critical to encouraging investment in carbon capture, use, and sequestration projects. Given this uncertainty, we might expect to see the Colorado legislature pick up that issue during the 2023 legislative session.