Four solar farm owners agreed in November 2022 to pay major fines in settlements with the Department of Justice (“DOJ”) and Environmental Protection Agency (“EPA”) to resolve stormwater management and construction permit violations. The federal court lawsuits involved two completed and two under-construction large-scale solar generating facilities, AL Solar A LLC (“AL Solar”) in Alabama, American Falls Solar LLC (“American Falls”) in Idaho, and Prairie State Solar LLC (“Prairie State”) and Big River Solar LLC (“Big River”) in Illinois. All four projects used a common construction contractor. The suits alleged violations of Clean Water Act (“CWA”) stormwater construction permits; failure to install and maintain proper stormwater controls; failure to conduct site inspections; failure to use qualified personnel for inspections; failure to accurately report and address stormwater issues; and the unauthorized discharge of sediment into waterways.

The fines against AL Solar totaled $500,000; against American Falls, $416,500; against Prairie State, $225,000; and against Big River, $175,000, coming to a total of over $1.3 Million. EPA and DOJ were clear that, in imposing these penalties, the agencies intended to send a strong warning to the solar and other renewable energy industries that, while these renewable energy projects are highly valued and critical to achieving sustainability and climate action goals, the agencies will strictly enforce and ensure compliance with stormwater and other environmental protection regulatory requirements. In the official EPA Notice of these settlements, Acting Assistant Administrator Larry Starfield of the EPA’s Office of Enforcement and Compliance Assurance emphasized, “These settlements send an important message to the site owners of solar farm projects that these facilities must be planned and built in compliance with all environmental laws, including those that prevent the discharge of sediment into local waters during construction.”

Four takeaways should be noted from these major fines:

• First and foremost, these large penalties should be an alarm to the owners and operators of solar and other renewable energy facilities that, while such operations are highly valued by the current Administration as critical to achieving its ambitious climate goals, federal agencies are and will be strictly overseeing and ensuring compliance with stormwater and other environmental protection requirements at renewable energy projects.
• Second, although nearly all states have been delegated authority over most stormwater and other CWA programs, the federal government always retains concurrent oversight and enforcement authority. Operators should both be aware of the sometimes unique additional requirements of each state where they operate and be prepared to prove compliance to both the lead state agency as well as EPA.
• Third, both the states and EPA have the authority to impose administrative penalties. Where, as here, the EPA and the states choose to involve DOJ or their state equivalent to bring a judicial enforcement action, they are sending a strong signal that these types of violations will be stringently punished.
• Finally and significantly, these cases demonstrate that the owners and operators of renewable energy projects will be held responsible for the environmental regulatory violations of their construction and other contractors.

Please contact a Davis Graham lawyer if you have any questions about these cases, compliance with stormwater management, or other regulatory requirements at your facilities.

SEC/SRO Update: DOJ Obtains First Criminal Sherman Act Monopolization Conviction in Decades; SEC Proposes New Oversight Requirements for Certain Services Outsourced by Investment Advisers; SEC Charges Mattel with Financial Misstatements and Former PwC Audit Partner with Improper Professional Conduct

Read more…

As part of ongoing attempts by the U.S. government to promote domestic availability of “critical minerals,” certain provisions of the Inflation Reduction Act (the “Inflation Act”) use tax credits as an incentive. Davis Graham wrote about critical minerals in our November 22, 2021 article on the Infrastructure Investment and Jobs Act (the “Infrastructure Act”).

The Inflation Act covers a wide range of policy topics, but the concept of critical minerals appears exclusively in Parts 4 and 5 of the act, addressing Clean Vehicles and Investment in Clean Energy Manufacturing and Energy Security, respectively.

Part 4 of the Inflation Act addressing Clean Vehicles modifies the existing New Qualified Plug-In Electric Drive Motor Vehicles credit in Section 30D of the Internal Revenue Code, renaming it the Clean Vehicle Credit. It provides for a maximum federal income tax credit of $7,500 for purchasing a new electric vehicle depending on the source of critical minerals used in the vehicle’s batteries if final assembly occurs in North America. The Inflation Act enhances the credit by increasing the baseline dollar limit, expanding the eligible vehicles, allowing a taxpayer to transfer the credit to a registered dealer, and eliminating the prior limit on credit-eligible vehicles.

With respect to critical minerals used in Clean Vehicle batteries, beginning in 2023, at least 40% of their value must be extracted or processed in the United States, or in any country with which the United States has a free trade agreement in effect, or must be recycled in North America. The required percentage of critical minerals value increases each year, up to 80% in 2027. Vehicles not meeting the value threshold are subject to a halving of the tax credit to $3,750. Additionally, if at least 50% of the vehicle’s battery components are manufactured or assembled in North America, an additional tax credit of $3,750 is available. Notably, the Inflation Act also renders vehicles ineligible for the tax credit if the vehicle’s batteries contain critical minerals or components extracted, processed, recycled, manufactured or assembled by “foreign entities of concern,” as defined in the Infrastructure Act. These nations currently include China, Russia, Iran and North Korea.

Department of Treasury guidance is required to be issued by December 31, 2022, regarding recordkeeping requirements to track the use and integration of critical minerals in the Clean Vehicle Credit program.

Part 5 of the Inflation Act establishes a new Advanced Manufacturing Production Tax Credit in Section 45X of the Internal Revenue Code. The credit applies to eligible components produced by a taxpayer/manufacturer in the United States and sold by the taxpayer. The critical minerals tax credit is 10% of the “costs incurred by the taxpayer with respect to production of such mineral.” Eligible components include any applicable critical mineral, defined in the Inflation Act to include aluminum, antimony, barite, beryllium, cerium, cesium, chromium, cobalt, dysprosium, europium, fluorspar, gadolinium, germanium, graphite, indium, lithium, manganese, neodymium, nickel, tellurium, tin, tungsten, vanadium, yttrium, and 23 other minerals – if they are purified to 99 percent by mass.

Outside of the Inflation Act, the U.S. government and other organizations may use other definitions and rely on additional criteria to identify a mineral as “critical.” For example, the Energy Act of 2020 (the “Energy Act”) defines a “critical mineral” as a non-fuel mineral or mineral material essential to the economic or national security of the U.S. and which has a supply chain vulnerable to disruption.

In addition to defining mineral criticality, the Energy Act directed the Department of the Interior’s U.S. Geological Survey (“USGS”) to update and publish a revised List of U.S. Critical Minerals (the “CML”). The initial CML, published in 2018 in response to Executive Order No. 13817, included 35 commodities and groups on the final list.[1] The USGS revised the list in 2022 to include 50 critical minerals;[2]
however, the increase in mineral commodities actually resulted from splitting the rare earth elements and platinum groups.[3] The 50 minerals included on the 2022 CML encompass those defined as critical minerals in Part 5 of the Inflation Act.

In preparing the 2022 CML, USGS removed Helium, Potash, Rhenium, and Strontium. Somewhat counterintuitively, USGS also removed Uranium from the CML, even though one might assume it would be a “critical” mineral because of the safety and national security concerns associated with nuclear power and nuclear weapons. However, in removing Uranium, the USGS relied upon the Mining and Mineral Policy Act of 1970, which defined Uranium as a fuel mineral, and, under the Energy Act, critical minerals do not include fuel minerals; water, ice, or snow; or common varieties of sand, gravel, stone, pumice, cinders, and clay.

While the Infrastructure Act did not make an express designation of mineral criticality, the 2022 CML is timely guidance for the use of Infrastructure Act funds, both for the USGS and other U.S. agencies and international partnerships. Like the Inflation Act, the Infrastructure Act contains several provisions aimed at increasing domestic production of rare earth elements and critical minerals to promote domestic supply chains and to alleviate the economic and national security concerns associated with the United States’ dependence on foreign suppliers. For the USGS specifically, the Infrastructure Act provided $320 million in funding for the Earth Mapping Resource Initiative (EMRI), for which the 2022 CML is the focus of USGS research quantifying critical mineral potential within the U.S. Relatedly, the Department of Energy (“DOE”)’s Critical Materials RDD&CA Program, piloted under the Energy Act, was expanded and supported by the Infrastructure Act. Backed by a $140 million investment, the DOE is also working to develop a full-scale rare earth element and critical minerals extraction and separation refinery using unconventional resources.

As regards critical minerals in the international context, in June of 2022, the State Department announced the establishment of the Minerals Security Partnership (“MSP”) to “bolster critical mineral supply chains.” The 11-member alliance between the U.S. and key partner countries is part of the Biden administration’s continued focus on critical mineral resources. This past week at a ministerial meeting of the MSP in New York, U.S. Secretary of State Antony Blinken remarked that the United States and its allies in MSP stand ready to support successful critical mineral projects. Noting that critical minerals production and processing “requires lots of investment and undertaking lots of risk,” Blinken reaffirmed that the MSP was committed to helping with both, including “providing a loan guarantee or debt financing.” The ministerial meeting included representation from the MSP member countries Australia, Canada, Finland, France, Japan, the Republic of Korea, Norway, Sweden, the United Kingdom, the United States, and the European Union. Additional minerals-rich countries in attendance included Argentina, Brazil, the Democratic Republic of the Congo, Mongolia, Mozambique, Namibia, Tanzania, and Zambia.

[1] Aluminum (bauxite), antimony, arsenic, barite, beryllium, bismuth, cesium, chromium, cobalt, fluorspar, gallium, germanium, graphite (natural), hafnium, helium, indium, lithium, magnesium, manganese, niobium, platinum group metals, potash, the rare earth elements group, rhenium, rubidium, scandium, strontium, tantalum, tellurium, tin, titanium, tungsten, uranium, vanadium, and zirconium. Final List of Critical Minerals 2018, U.S. Department of the Interior, 83 Fed. Reg. 23295, 2018, https://www.govinfo.gov/content/pkg/FR-2018-05-18/pdf/2018-10667.pdf

[2] Aluminum, antimony, arsenic, barite, beryllium, bismuth, cerium, cesium, chromium, cobalt, dysprosium, erbium, europium, fluorspar, gadolinium, gallium, germanium, graphite, hafnium, holmium, indium, iridium, lanthanum, lithium, lutetium, magnesium, manganese, neodymium, nickel, niobium, palladium, platinum, praseodymium, rhodium, rubidium, ruthenium, samarium, scandium, tantalum, tellurium, terbium, thulium, tin, titanium, tungsten, vanadium, ytterbium, yttrium, zinc, and zirconium. Final List of Critical Minerals 2022, U.S. Department of the Interior, 87 Fed. Reg. 10381, 2022, https://www.govinfo.gov/content/pkg/FR-2022-02-24/pdf/2022-04027.pdf

[3] Platinum group metals (Iridium, Palladium, Platinum, Rhodium, Ruthenium, and Osmium) were previously listed together as one group; in the 2022 CML, they have been separated, and Iridium and Osmium have been removed from the list. Likewise, metals belonging to the rare earth elements group (Cerium, Gadolinium, Lanthanum, Neodymium, Praseodymium, and Samarium) were previously listed together as one group; in the 2022 CML, they have been separated.

In Northwest Landowners Association v. State, No. 20210148, 2022 N.D. Lexis 152 (N.D. Aug. 4, 2022), the North Dakota Supreme Court held that portions of Senate Bill 2344 related to pore space violated the takings clauses of the North Dakota and United States constitutions.

In 2019, the North Dakota Legislative Assembly enacted S.B. 2344, which amended and reenacted sections to three existing statutes (N.D.C.C. §§ 38-08-25, 38-11.1-01, and 38-11.1-03) and created and enacted a new statutory section (N.D.C.C. § 47-31-09). The legislation was enacted to clarify the use of pore space.

In S.B. 2344, the Legislative Assembly defined pore space as “a cavity or void, whether natural or artificially created, in a subsurface sedimentary stratum,” and vested the surface owner with pore space ownership (N.D.C.C. §§ 47-31-02 and 03). Section 1 of S.B. 2344 added a subsection to N.D.C.C. § 38-08-25, which allowed an oil and gas operator to use subsurface pore space and denied the surface owner the right to exclude others or to demand compensation for the subsurface use. Section 2 of S.B. 2344 amended N.D.C.C. § 38-11.1-01 to supplement existing legislative findings and add an interpretative provision. Additionally, section 3 of S.B. 2344 amended and adopted a new definition of “land” to “exclude pore space” in the North Dakota Damage Compensation Act, with the result being that a mineral developer would not be required to compensate the surface owner for “lost land value, lost use of and access to the surface owner’s land, and lost value of improvements caused by drilling operations” (N.D.C.C. §§ 38-11.1-03 and 04). Lastly, section 4 of S.B. 2344 barred tort claims, including trespass and nuisance claims, for injection or migration of substances into pore space.

The Northwest Landowners Association sued the state, arguing that S.B. 2344 constitutes a taking because “it strips landowners of their right to possess and use the pore space within their lands and allows the State of North Dakota to directly redistribute that right to others without the consent of or compensation to the landowners.” The district court granted summary judgment in favor of the Northwest Landowners Association and concluded that S.B. 2344 constitutes a taking under both federal and state law because it takes landowners’ property without compensation for the benefit of private parties and also bars landowners from seeking tort remedies. The district court declared the entirety of S.B. 2344 invalid and issued an injunction preventing enforcement of the law.

The North Dakota Supreme Court agreed with the district court and affirmed that S.B. 2344 constitutes a per se taking because it would allow third-party oil and gas operators to physically invade a landowner’s property by injecting substances into the landowner’s pore space without the surface owner’s consent or compensation. Additionally, the court held that the newly-enacted definition of “land” was unconstitutional because it excludes “pore space.” And, finally, the court held that section 4 of S.B. 2344 barring tort claims for injection or migration of substances into pore space was unconstitutional. However, the court declined to find the entire bill invalid, and reversed the district court’s decision to the extent it declared the remainder of S.B. 2344 invalid. Thus, the bill’s definition of surface owner (“any person who holds record title to the surface estate on which a drilling operation occurs or is conducted”) and pore space (as defined above) remain valid.

By invalidating the most significant provisions of S.B. 2344, the North Dakota Supreme Court has cast uncertainty on rights to pore space for carbon capture use and sequestration (“CCUS”) in that state. Clear legislation of pore space can reduce some risk and uncertainty surrounding CCUS projects. For help navigating CCUS projects, please contact John Jacus, Katie Schroder, Katie Roux, or Kathleen Pritchard.

On September 14, 2022, the U.S. Fish and Wildlife Service (USFWS) published a proposed rule to list the tricolored bat as endangered under the Endangered Species Act (ESA). Notably, the USFWS declined to propose to designate critical habitat for the species after finding such a designation would not be prudent.

The tricolored bat’s range includes some or all of 39 states, including eastern Colorado, eastern New Mexico, eastern Wyoming, Kansas, Oklahoma, and Texas:

Source: USFWS Environmental Conservation Online System.

During the winter, tricolored bats are often found in caves, abandoned mines, and road-associated culverts. During the remainder of the year, tricolored bats mainly are found in forested habitats but may also be found in Spanish moss, pine trees, and occasionally human structures.

The USFWS’s listing proposal followed several years of inactivity by the agency regarding the species. In 2016, the Center for Biological Diversity filed a petition requesting that the USFWS list the species as threatened or endangered. In 2017, the USFWS published a 90-day finding that the petition presented substantial scientific or commercial information indicating that listing may be warranted. Since then, the USFWS had not taken any action on the petition. In the proposed rule, the USFWS specified that the proposed rule also serves as the 12-month finding on the listing petition.

The USFWS identified white-nosed syndrome, a disease caused by a fungal pathogen affecting bats, as the principal threat to the species. The USFWS, however, identified wind energy-related mortality as a “consequential stressor” to the species at local and regional levels. The USFWS also identified habitat loss and climate change as impacting the tricolored bat.

In the proposed rule, the USFWS declined to designate critical habitat. The USFWS found this designation not to be prudent because the species is not principally threatened by human activity and because a critical habitat designation would not benefit the species.

The USFWS is accepting comments on the proposed listing until November 14, 2022. On October 12, 2022, the UFWS will hold an informational meeting from 6 to 7:30 pm (ET) and a public hearing from 7:30 to 8:30 pm (ET).

The ESA requires the FWS to publish one of the following by September 14, 2023: a final rule listing the tricolored bat; a notice withdrawing the proposed rule; or a notice that the USFWS requires an additional six months to either publish a final rule or withdraw the proposed rule.

Senate Legislative Counsel, Draft copy of ELT22557 0PR Released September 21, 2022

This week, Senator Joe Manchin released an updated draft of a permitting bill that is the product of a deal brokered by the senator for his support for the Inflation Reduction Act. Generally, the bill aims to reduce regulatory barriers to federal approvals of infrastructure projects. Most controversially, the bill directs federal agencies to approve the Mountain Valley pipeline, a natural gas pipeline through Virginia and West Virginia that is over 90% constructed but has been delayed due to various permitting disputes.

The bill contains two subtitles, each with different objectives. The first subtitle (Subtitle A, “Accelerating Agency Reviews”) outlines broad permitting reforms intended to expedite agency decision-making on infrastructure permitting. Although the environmental interests have expressed opposition to the bill, it has the potential to streamline permitting of both renewable and conventional energy projects.

Within Subtitle A, section 12 outlines a variety of measures that attempt to streamline permitting of projects that require multiple federal approvals and preparation of an environmental impact statement. Most significant, this section would impose a 150-day statute of limitations for judicial challenges to such projects. Additionally, this section proposes to identify roles and requirements of a lead permitting agency, coordinate cooperating and participating agencies, and require preparation of a single National Environmental Policy Act (NEPA) analysis to the extent practicable and legal. This section would also require agencies to establish project schedules and establish maximum lengths for public comment periods during the permitting process. Moreover, this section would require federal agencies to develop new categorical exclusions under NEPA.

Many of these measures are not novel. They resemble the permitting efficiencies available for projects that qualify for treatment under Title 41 of the Fixing America’s Surface Transportation (FAST) Act, as amended by the Bipartisan Infrastructure Law, and/or those efficiencies outlined in the now-revoked Executive Order No. 13807, “Establishing Discipline and Accountability in the Environmental Review and Permitting Process for Infrastructure Projects” (Aug. 15, 2017). Thus, the permitting bill reflects a congressional recognition that these measures are necessary to improve infrastructure permitting.

For a subset of infrastructure projects, section 13 within Subtitle A would offer even more efficiencies. It requires the President to identify 25 projects of “strategic national importance” in various industries and sectors. Initially, four such projects must relate to critical minerals; six projects must relate to generation or storage of electricity from non-fossil sources or manufacturing of clean energy equipment; five projects must relate to fossil fuels or biofuels; two projects must relate to electronic transmission or grid-enhancements; two projects must relate to carbon capture, transportation, or storage; and one project must relate to clean hydrogen. The President must maintain and update this list of projects for 10 years.

For these projects of strategic national important, the bill would impose timelines for environmental review. The bill attempts to give teeth to these deadlines by requiring the President to submit regular reports to congressional committees on the status of these projects. Additionally, the bill provides additional funding for environmental reviews of these projects.

The second subtitle in the bill (Subtitle B, “Modernizing Permitting Laws”) contains a section specific to the Mountain Valley Pipeline. After finding that the Mountain Valley Pipeline is in the national interest, section 24 of the bill would direct federal agencies to re-issue approvals necessary for the pipeline that a federal court of appeals had vacated and remanded. The bill would also exempt these approvals from further judicial review. All other federal approvals relating to the validity of section 24 and the Mountain Valley Pipeline would be subject to review by the U.S. Court of Appeals for the District of Columbia Circuit.

Section 23 of Subtitle B would amend the Natural Gas Act to include hydrogen in the definition of “natural gas.” The remaining sections of Subtitle B are not summarized in this article but are nonetheless significant. Section 21 would amend the Clean Water Act to streamline decision-making under section 401. Section 22 would amend the Federal Power Act, 16 USC 824a(2).

Senator Manchin may attach the permitting bill to legislation funding the federal government. Whether Congress will enact the permitting bill into law, however, depends on the whims of politics. Republicans have suggested the bill does not propose meaningful permitting reforms, while progressives are resisting the proposal to authorize the Mountain Valley pipeline. Thus, it is difficult to predict whether the changes proposed in the permitting bill will become final.

Subtitle A – Accelerating Agency Reviews

Section 11 – Definitions

Section one contains definitions that are necessary to understand the provisions in sections two and three:

Agency – any agency, department, or other unit of Federal, State, local, or Tribal government

Authorization – any license, permit, approval, finding or other administrative decision required or authorized under Federal law (including regulations) to design, plan, site, construct, reconstruct, or commence operations of a project.

Cooperating Agency – any Federal agency (and a State, Tribal, or local agency if agreed on by the lead agency) other than a lead agency, that has jurisdiction by law or special expertise with respect to an environmental impact relating to a project.

Environmental Document – any of the following, as prepared under NEPA:

An environmental assessment (EA).

A finding of no significant impact.

An environmental impact statement (EIS).

A record of decision.

Environmental impact statement

Environmental review process – the process for preparing an EIS, EA, categorical exclusion, or other document required to be prepared to achieve compliance with NEPA, including pre-application consultation and scoping processes.

Indian Tribe

Lead Agency – with respect to a project, means (A) the Federal agency preparing, or assuming primary responsibility for, the authorization or review of the project; and (B) if applicable, at State, local, or Tribal government entity serving as a joint lead agency for the project.

NEPA

NEPA implementing regulations

Participating Agency – an agency participating in an environmental review or authorization for a project

Project Sponsor – an entity, including any private, public, or public-private entity, that seeks authorization for a project.

Section 12 – Streamlining Process for Authorizations and Reviews of Energy and Natural Resources Projects

(a) Definitions

Categorical exclusion – means within the meaning of NEPA

Major project – a project (A) for which multiple authorizations, reviews, or studies are required under a Federal law other than NEPA; and (B) with respect to which the head of the lead agency has determined that (i) an EIS is required; or (ii) an EA is required, and the project sponsor requests that the project be treated as a major project.

Project – means a project (A) proposed for the construction of infrastructure (i) to produce, generate, store, or transport energy; (ii) to capture, remove, transport, or store carbon dioxide; or (iii) to mine, extract, beneficiate, or process minerals; and (B) that, if implemented as proposed by the project sponsor, would be subject to the requirements that (i) an environmental document be prepared; and (ii) the applicable agency issue an authorization of the activity.

Secretary Concerned means, as appropriate – (A) the Secretary of Agriculture, with respect to the Forest Service; (B) the Secretary of Energy; (C) the Secretary of the Interior; (D) the Federal Energy Regulatory Commission; (E) the Secretary of the Army, with respect to the Corps of Engineers; and (F) the Secretary of Transportation, with respect to the Maritime Administration.

(b) Applicability – the project development procedures under this section:

Shall apply to (i) all projects for which an EIS is prepared; and (ii) all major projects.

May apply, as requested by a project sponsor and to the extent determined appropriate by the Secretary concerned, to other projects for which an environmental document is prepared.

Shall not apply to

(i) any project subject to section 139 of title 23, USC[1];

(ii) any project that is a water resources development project of the Corps of Engineers; or

(iii) any authorization of the Corps of Engineers if that authorization is for a project that alters or modifies a water resources development project of the Corps of Engineers.

Does not preclude the use of an authority provided under any other provision of law including for a covered project under title 41 of the FAST Act.

(c) Lead Agencies – requirements

Expedite Resolution of Environmental Review Process. Shall have the authority and responsibility to take such actions as are necessary and appropriate to facilitate the expeditious resolution of the environmental review process for the project.

Prepare Environmental Documents. Shall have the authority and responsibility to prepare any required EIS or other environmental document or to ensure that same are completed in accordance with this section and applicable Federal law.

Identify and Invite Participating Agencies. Shall not later than 45 days after the date of publication of a notice of intent to prepare an EIS or the initiation of an EA, as applicable, for a project:

Identify any other agencies that may have financing, environmental review, authorization, or other responsibilities with respect to the project.

Invite the identified agencies to become participating agencies in the environmental review process for the project.

Establish, as part of the invitation, a deadline for the submission of a response, which may be extended by the lead agency for good cause.

Use of Data, Analyses, and Documentation prepared under State or Tribal Laws and Procedures. Shall consider and, as appropriate, rely on, adopt, or incorporate by reference, baseline data, analyses, and documentation that have been prepared for the project under the laws and procedures of a State or an Indian Tribe if the lead agency determines that those laws are of equal or greater rigor, and the data, analysis, or documentation was prepared under circumstances that allowed for opportunities for pubic participation; consideration of alternatives and environmental consequences; and other required analyses that are substantially equivalent to what would have been prepared by the lead agency pursuant to NEPA.

Compliance With Design and Mitigation Commitments. Shall ensure that the project sponsor complies with design and mitigation commitments for the project made jointly by the lead agency and the project sponsor.

Supplementation of Environmental Document. Shall ensure that the environmental documents are appropriately supplemented if changes become necessary with respect to the project.

(d) Participating Agencies

Applicability – excludes covered projects under section 41001 of the FAST Act.

Mandatory designation of invited federal agencies. Any Federal agency that is invited by a lead agency to participate in the environmental review process for a project shall be designated as a participating agency by the lead agency, unless the invited agency informs the lead agency, in writing, that the invited agency has no responsibility for or interest in the project.

A participating agency shall provide comments, responses, studies, or methodologies relating to the areas within their special expertise or jurisdiction; and shall use the environmental review process to address any environmental issues of concern to the agency.

Federal Cooperating Agencies. A Federal agency that has not been invited to participate in the environmental review process for a project but that is required to make an authorization or carry out an action for a project shall notify the lead agency and work with the lead agency to ensure that the agency making the authorization or carrying out the action is treated as a cooperating agency for the project.

Any agency designated as a cooperating agency shall also be designated by the applicable lead agency as a participating agency under the NEPA implementing regulations.

(e) Coordination of Required Environmental Reviews.

Application of the FAST Act – Coordination of Required Environmental Reviews and Authorizations. The lead agency and each participating agency for a project shall apply the requirements of section 41005 of the FAST Act (42 USC 4370m-4) to the project, subject to the condition that any reference in that section to a “covered project” shall be considered a reference to the project under this section.

Single Environmental Document. To the maximum extent practicable and consistent with Federal law, to achieve compliance with NEPA, all Federal authorizations and reviews that are necessary for a project shall rely on a single environmental document. [Subject to specified exceptions.] To the maximum extent practicable, the lead agency shall develop environmental documents sufficient to satisfy the NEPA requirements for any authorization or other Federal action required for the project. Each participating agency shall cooperate with the lead agency and provide timely information to assist the lead agency in carrying out the requirement for a single environmental document.

(f) Modification of draft environmental impact statement by errata sheets. If the lead agency modifies the draft EIS in response to comments, the lead agency may write on errata sheets attached to the EIS in lieu of rewiring the EIS, subject to specified conditions (such as modifications shall be confined to minor factual corrections; or an explanation of the reasons why the comments do not warrant additional response from the lead agency).

(g) Coordination Plan and Scheduling

90 Days to establish coordination plan. Not later than 90 days after the date of publication of a notice of intent to prepare an EIS, or the initiation of an EA, as applicable, the lead agency shall establish a plan for coordinating public and agency participation in, and comment regarding, the environmental review process and authorization decisions for the project or appliable category of projects.

Establish and maintain schedule. Lead agency shall establish and maintain a schedule for completion of the environmental review process and authorization decisions.

Major Project Schedule – 2 years for EIS and 2 year for EA. To the maximum extent practicable and consistent with applicable federal law, in the case of a major project, the lead agency shall develop a schedule that is consistent with completing:

The environmental review process – not later than 2 years after the date of publication of the lead agency of a notice of intent to prepare an EIS or not later than 1 year after the date on which the head of the lead agency determines that an EA is required to a finding of no significant impact.

Authorizations required for project construction – not later than 180 days after the date of issuance of a record of decision or a finding of no significant impact.

Modification of Schedule. Factors for consideration in establishing a schedule are provided in the bill. Provisions for lengthening or shortening a schedule for good cause are provided in the bill.

Failure to Meet Deadline. If a participating Federal Agency fails to meet a schedule deadline, the participating Federal agency shall notify the Office of Management and Budget and the Secretary concerned regarding that failure.

Comment Deadlines. The lead agency shall also establish the following deadlines for comment during the environmental review process:

60 days for agencies and the public on draft EIS – not more than 60 days after public in the Federal Register of a notice of the date of public availability of the draft [subject to specified exceptions]

45 days for all other comment periods – for all other comment periods established by the lead agency for agency or public comment for a Federal authorization or in the environmental review process, a period of not more than 45 days beginning on the first date of availability of the materials regarding which comment is request, unless a different deadline of not more than 60 days is established by agreement of the lead agency and all participating agencies, in consultation with the project sponsor.

No reduction in public comment time periods. Nothing in this subsection reduces any time period provided for (i) public comment in the environmental review process; or (ii) an authorization for a project under applicable Federal law.

Nothing in this subsection creates a requirement for an additional public comment opportunity in addition to any public comment opportunity required for a project under applicable Federal law. Nothing in this subsection creates a new requirement for public comment on a project for which an EA is being prepared. Nothing in this subsection affects or creates new requirements for a project or activity eligible for a categorical exclusion.

(h) Issue Identification and Resolution

Lead agency and each participating agency shall work cooperatively in accordance with this section to identify and resolve issues that could:

(A) delay final decision making for any authorization for a project;

(B) delay completion of the environmental review process for a project; or

(C) result in the denial of any authorization required for the project under applicable law.

Accelerated Issue Resolution and Referral

(A) Issue resolution meeting to be conducted by the lead agency to resolve issues – if requested by a participating agency, project sponsor, or the Governor of a State in which a project is located. Initial meeting – not later than 30 days after receipt of a request.

Lead agency can also convene an issue resolution meeting at any time to resolve issues, without request.

(B) Elevation to the head of the lead agency – if resolution is not achieved by 30 days after the date of the initial meeting, elevated to the head of the lead agency. Leadership issue resolution meeting to be convened not later than 90 days after the date of the initial meeting.

(C) Referral to the Council on Environmental Quality – if resolution is not achieved by 30 days after the date on which a leadership issue resolution meeting is convened. To be conveyed by the Council not later than 30 days after the date of receipt of a referral.

(D) Referral to the President – if resolution not achieved by 30 days after the date of the meeting convened by the Council on Environmental Quality.

(i) Enhanced Technical Assistance by the Lead Agency. At the request of a project sponsor, participating agency, or the Governor or a state in which a covered project is located, the head of the lead agency may provide technical assistance to resolve any outstanding issues that are resulting in project delay including by:

(A) providing additional staff, training, and expertise;

(B) facilitating interagency coordination;

(C) promoting more efficient collaboration; and

(D) supplying specialized onsite assistance.

A covered project in this subsection is a project (A) that has a pending environmental review or authorization under NEPA; and (B) for which the lead agency determines a delay to the schedule is likely.

(j) Judicial review and savings clauses

Except as provided in subsection (k) [150 day statute of limitations for claims], nothing in this section affects the reviewability of any final Federal agency action in a court of the United States or any State.

Does not supersede, amend, or modify NEPA or any Federal environmental law; or affect the responsibility of any Federal officer to comply with or enforce any Federal law.

Does not preempt or interfere with (A) any practice of seeking, considering, or responding to public comment; (B) any power, jurisdiction, responsibility, or authority of a Federal, State, or local government agency, Indian Tribe, or project sponsor with respect to carrying out a project; or (C) any other provision of law applicable to a project, plan, or program.

(k) Statute of Limitations, Remands, and Judicial Review

150 days to file claims

Notwithstanding any other provision of law

A claim arising under Federal law seeking judicial review of an authorization issued or denied by a Federal agency for a project shall be barred unless the claim is filed by 150 days after the later of the date on which the authorization is final in accordance with the law under which the agency action is taken and the date of publication of a notice that the environmental document is final in accordance with NEPA, unless a shorter time is specified in the Federal law pursuant to which judicial review is allowed.

Supplemental or revised environmental documents – considered a separate final agency action for purposes of the 150-day limit.

Remanded Actions

If a court remands an agency action for a project to a federal agency, the court must set a reasonable schedule and deadline for the agency to act on remand. The deadline may not exceed 180 days from the date of the court order unless a longer time period is necessary to comply with applicable law. Federal agencies must take necessary actions for the expeditious disposition of an action on remand in accordance with this schedule.

Random Assignment of Cases

Federal district courts and courts of appeals must randomly assign cases seeking judicial review of a federal agency authorization for a project to avoid the appearance of favoritism or bias.

(l) Improving Transparency in Project Status – not later than 120 days after enactment of this Act

Secretary to make publicly available major project information

Status, schedule and progress of each major project with respect to compliance with NEPA, any authorization and any other Indian Tribe, State, or local agency authorization

List of participating agencies

Establish major project tracking reporting standards to track major projects from initiation through final authorizations or withdrawal of project and to update the information

Federal, State, and Local Agency Participation in Transparency

Federal participating agencies shall provide information to the Secretary regarding major project status. Secretary shall encourage State and local agencies participating in the environmental review process or authorization process for a major project to provide information.

(m) Secretaries to establish performance accountability systems for the agency represented by the Secretary concerned – within 1 ear after date of enactment of the Act

(n) Programmatic Compliance – Secretary concerned shall allow for the use of programmatic approaches to conduct environmental review that:

(A) eliminate repetitive discussions of the same issue;

(B) focus on the issues ripe for analysis at each level of review; and

(C) are consistent with (i) NEPA; and other applicable laws.

Details provided in the draft bill.

(o) Development of Categorical Exclusions – 180 days after enactment of the Act and every 4 years thereafter

Each Secretary concerned, in consultation with the Chair of the Council on Environmental Quality, shall:

(A) in consultation with other listed agencies, as applicable, identify each categorical exclusion available to such an agency that would accelerate delivery of a project if the categorial exclusion was available to the Secretary concerned; and

(B) collect existing documentation and substantiating information relating to each categorial exclusion identified.

Agencies:

Department of Agriculture

Department of the Army

Department of Commerce

Department of Defense

Department of Energy

Department of Interior

FERC

Any other Federal agency that has participated in an environmental review process for a project, as determined by the Chair of the Council on Environmental Quality

Not later than 1 year after date on which categorial exclusions are identified, each Secretary shall:

Determine whether such categorial exclusion meets the applicable criteria for a categorial exclusion under the NEPA implementing regulations; and any relevant regulations of the agency represented by the Secretary Concerned.

Public a notice of proposed rulemaking to propose the adoption of any identified categorical exclusions that meet the above criteria.

(p) Additions to Categorial Exclusions – surveys within 180 days after enactment of the Act, and not later than 5 years thereafter

Each Secretary to conduct a survey regarding the use by the agency of categorical exclusions for projects during the preceding 5 year period

Public a review of the survey

Solicit from relevant project sponsors requests for new categorical exclusions.

Not later than 120 days after the date of the solicitation of requests for new categorical exclusions, the Secretary shall:

Public a notice of proposed rulemaking to propose the adoption of any such new categorical exclusions to the extent they meet the applicable criteria under NEPA and any relevant regulations.

Section 13 – Prioritizing Energy Projects of Strategic National Importance

(a) Definitions

Critical mineral has the meaning given the term in section 7002(a) of the Energy Act of 2020 (30 USC 1606(a). That definition is:

The term “critical mineral” means any mineral, element, substance, or material designated as critical by the Secretary under subsection (c).

“Secretary” refers to the Secretary of Energy.[2]

Designated Project – an energy project of strategic national importance designated for priority Federal Review.

(b) Designation of Projects – not later than 90 days after enactment of the Act – 25 projects of strategic national importance to be designated:

The President, in consultation with the Secretary of Energy, Secretary of the Interior, the Administrator of the Environmental Protection Agency, FERC, and the heads of any other relevant Federal departments or agencies, as determined by the President to designate 25 energy projects of strategic national importance for priority Federal Review, and publish a list of the designated projects in the Federal Register.

Updates – not later than 180 days after date of publication of the list in the Federal Register and every 180 days thereafter during the 10-year period after publication, the President shall publish an updated list, which shall:

Include not less than 24 designated projects; and

Include each previously designated project until a final decision or withdrawal

Project types – during the 7 year period beginning on the date of publication of the first list, not fewer than:

(A) 4 projects for mining, extraction, beneficiation or processing of critical minerals (not fewer than 3 shall include new mining or extraction); and for which critical mineral production may occur as a byproduct.

(B) 6 shall be projects to generate electricity or store energy without the use of fossil fuels; or to manufacture clean energy equipment.

(C) 5 shall be projects to produce, process, transport, or store fossil fuel products, or biofuels, including projects to export or import those products from certain specified nations.

(D) 2 shall be electric transmission projects or projects using grid-enhancing technology.

(E) 2 shall be projects to capture, transport, or store carbon dioxide, which may include the utilization of captured or displaced carbon dioxide emissions.

(F) 1 shall be a project to produce, transport, or store clean hydrogen, including projects to export or import those products from certain specified nations.

Project types – during the 3 year period beginning 7 years after the date of publication of the first list, not fewer than:

(A) 2 shall be projects for the mining, extraction beneficiation, or processing of critical mineral

(B) 3 shall be projects described in (B) above

(C) 3 shall be projects described in (C) above

(D) 1 shall be a project described in (D) above

(E) 1 shall be a project described in (E) above

(F) 1 shall be a project described in (F) above.

President to maintain a list of the designated projects that meet the minimum threshold for the applicable category – during the 10-year period after publication of the first list.

If insufficient applications, minimum threshold does not apply until there is a sufficient number of applications meeting the requirements for a designated project.

(c) Selection and Priority Requirements

Projects selected based on a review of applications for authorizations or other reviews submitted to the Corp of Engineers, the Department of Defense, the Department of Energy, the Department of the Interior, the Forest Service, the FERC, the Nuclear Regulatory Commission, the Maritime Administration, and the Federal Permitting Improvement Steering Council.

President shall designate only projects that the President determines are likely:

(A) to require an EA or EIS under NEPA,

(B) require review by more than 2 Federal or State agencies

(C) have a total project cost of more than $250 million; and

(D) have sufficient financial support from the project sponsor to ensure project completion.

President shall give priority to projects the completion of which will significantly advance 1 or more of the following objectives:

(1) reducing energy prices in the US

(2) reducing greenhouse gas emissions

(3) improving electric reliability in North America

(4) advancing emerging energy technologies

(5) improving the domestic supply chains for, and manufacturing of, energy products, energy equipment, and critical minerals,

(6) increasing energy trade between the US and nations that are signatories to free trade agreements with the US that cover the trade of energy products; members of NATO; members of the Organization for Economic Cooperation and Development; nations with a transmission operator that is included in the European Network of Transmission System Operators for Electricity, including as an observer member; or any other country designated as an ally or partner nation by the President for purposes of this section.

(7) reducing the reliance of the US on the supply chains of foreign entities of concern as defined in section 40207 of the Infrastructure Investment and Jobs Act, 42 USC 1874(a)

(8) to the extent practicable, minimizing development impacts through use of existing rights-of-way, facilities; or other infrastructure.

(9) creating jobs with wages at rates not less than those prevailing on similar projects in the locality as determined by the Secretary of Labor; and with consideration of the magnitude and timing of the direct and indirect employment impacts of carrying out the project.

Other priority – In addition to the priorities specified above, the President shall give priority to projects the completion of which will significantly reduce greenhouse gas emissions, including projects that involve or enable switching from a higher-emitting energy source to a lower-emitting energy source; or replacing a higher-emitting facility with a lower-emitting facility, including through modernization of an existing facility.

(d) Prioritizing completion of environmental review process and authorizations for designated projects

The President, in consultation with the applicable department and agency heads, the Director of the Office of Management and Budget, the Chair of the Council o Environmental Quality, and the Federal Permitting Improvement Steering Council, direct Federal agencies through executive order to prioritize the completion of the environmental review process and authorizations for designated projects.

Timelines – to the maximum extent practicable and consistent with Federal law, the President shall seek to complete:

Any environmental review process:

If EIS required, not later than 2 years after date of publication of notice of intent to prepare an EIS

If an EA is required, not later than 1 year after the date on which the head of the lead agency determines that an EA is required to a finding of no significant impact

Any outstanding authorizations required for project construction – within 180 days of the issuance of a record of decision or finding of no significant impact

A designated project is a major project under section 2 of the Act.

Prioritization following court action

President to ensure that any Federal review or authorization for a designated project that is remanded or vacated by a court of law is prioritized for further agency action.

(e) NEPA – not modified by this section.

The act of designating a project shall not be subject to NEPA.

(f) Reports – 180 days after enactment and every 90 days thereafter

President to submit to the Committee on Energy and Natural Resources of the Senate and the Committee on Energy and Commerce and the Committee on Natural Resources of the House, report describing each designated project, basis for designation, outstanding authorizations, environmental reviews, consultations, public comment periods, or other Federal, State, or local reviews required for project completion, and estimated completion dates or explanations of delays regarding same.

(g) Funding – Out of the $350 million appropriated to the Federal Permitting Improvement Steering Committee’s Environmental Review Improvement Fund in the Inflation Reduction Act for fiscal year 2023, $250 million shall be used to provide funding to agencies to support more efficient, accurate, and timely reviews of designated projects. ($1.5 million limit per designated project.) Does not supplant existing funding mechanisms.

Sections 23 and 24 of Subtitle B – Modernizing Permitting Laws

Section 23 – Definition of Natural Gas under the Natural Gas Act

Amends the definition of “natural gas” in section 2 of the Natural Gas Act, 15 USC 717a, to include hydrogen, either mixed or unmixed with natural gas.

Section 24 – Authorization of Mountain Valley Pipeline

(a) Finding – Congress finds that timely completion of the Mountain Valley Pipeline is in the national interest and is necessary to ensure an adequate and reliable supply of natural gas to consumers at reasonable prices, facilitate an orderly transition of the energy industry to cleaner fuels, and reduce carbon emissions.

(b) Purpose – Purpose is to require federal agencies to take all necessary actions to permit the timely completion of construction and operation of the Mountain Valley Pipeline without further administrative judicial delay or impediment.

(c) Definitions – “Secretary” means the Secretaries of Agriculture, Interior, or the Army.

(d) Authorization of necessary approvals

Requires the following actions within 30 days of enactment of the act:

The Secretary of the Interior must issue a biological opinion and incidental take statement for the Mountain Valley Pipeline, substantially in the form of the biological opinion and incidental take statement for the project issued by the U.S. Fish and Wildlife Service on September 4, 2020.[3]

The Secretary of the Interior must issue all rights-of-way, permits, leases, and other authorizations for the construction, operation, and maintenance of the Mountain Valley Pipeline, substantially in the form approved in the BLM’s record of decision dated January 14, 2021.[4]

The Secretary of Agriculture must amend the Land and Resource Management Plan for the Jefferson National Forest as necessary to permit the construction, operation, and maintenance of the Mountain Valley Pipeline, substantially in the form approved in the Forest Service’s dated January 2021.[5]

The Secretary of the Army shall issue all permits and verifications necessary to permit the construction, operation, and maintenance of the Mountain Valley Pipeline across waters of the United States.

FERC shall approve any amendments to the certificate of public convenience and necessity issued by the Commission on October 13, 2017 (161 FERC 61,043) and grant any extensions necessary to permit the construction, operation, and maintenance of the Mountain Valley Pipeline.

(e) Authority to modify prior decisions or approvals – Allows the relevant Secretary to modify the approvals described in section (d) if the Secretary determines the modification is necessary to correct a deficiency in the record or to protect the public interest or the environment.

(f) Relationship to other laws – The provisions of (d) supersede the provisions of other laws and regulations relating to relating to an administrative determination as to whether the biological opinion, incidental take statement, right-of-way, amendment, permit, verification, or other authorization shall be issued for the Mountain Valley Pipeline.

(g) Judicial review

The actions described in section (d) shall not be subject to judicial review.

The U.S. Court of Appeals for the District of Columbia Circuit has original and exclusive jurisdiction over claims challenging the invalidity of section 24 of the act, alleging an action is beyond the scope of authority conferred by section 24, and relating to any action by a Secretary or FERC relating to the Mountain Valley Pipeline.

[1] Efficient environmental reviews for project decision making and One Federal Decision – applies to any highway project, public transportation capital project, or multimodal project that, if implemented as proposed by the project sponsor, would require approval by any operating administration or secretarial office within the Department of Transportation.

[2] Section 7002 promotes a secure and robust critical minerals supply chain by (1) requiring the executive branch designate a list of critical minerals and update that list every three years; (2) requiring USGS to conduct domestic resource assessments of critical minerals and to make that information publicly available; (3) requiring the Department of the Interior and Department of Agriculture to publish critical mineral Federal Register notices within 45 days of being finalized; (4) directing the Secretary of Energy to conduct an RDD&CA program on the development of alternatives to, recycling of, and efficient production and use of critical materials (which may be carried out by DOE’s Critical Materials Energy Innovation Hub); (5) directing the Secretary of Energy and the Director of the Energy Information Administration to develop analytical and forecasting tools to evaluate critical minerals markets; (6) requiring the Secretary of Labor and the Director of the National Science Foundation to develop curriculum and a program for institutions of higher education to build a strong critical minerals workforce; and (7) reauthorizing the National Geological and Geophysical Data Preservation Program through fiscal year 2029.

https://www.energy.senate.gov/services/files/32B4E9F4-F13A-44F6-A0CA-E10B3392D47A#:~:text=Section%203201%20establishes%20an%20RD%26D,with%20the%20Secretary%20of%20Defense.

[3] The U.S. Court of Appeals for the Fourth Circuit vacated and remanded the 2020 biological opinion and incidental take statement in Appalachian Voices v. U.S. Department of the Interior, 25 F.4th 259 (4th Cir. 2022).

[4] The U.S. Court of Appeals for the Fourth Circuit vacated and remanded this Record of Decision in Wild Virginia v. U.S. Forest Service, 24 F.4th 915 (4th Cir. 2022).

[5] The U.S. Court of Appeals for the Fourth Circuit vacated and remanded this Land and Resource Management Plan in Wild Virginia v. U.S. Forest Service, 24 F.4th 915 (4th Cir. 2022).

Our June 2022 Clean Energy and Sustainability Group Newsletter included a status report on the Application of Public Service Company of Colorado for approval of its 2021 electric resource plan (“ERP”) and clean energy plan (“CEP”) in proceeding No. 21A-0141E (the “Application”). At the time of the writing of that status report, the Colorado Public Utilities Commission (the “Commission”) had held its first deliberations meeting, on March 14, 2022, to consider the Application. Additionally, an Updated Non-Unanimous Partial Settlement Agreement had been filed on April 26, 2022 (the “Updated Settlement”), and an evidentiary hearing held on May 17, 2022 on the Updated Settlement.

Since that time, the Commission worked through the issues in the Application in deliberations held on June 10, 2022, June 15, 2022, and June 22, 2022 resulting in a written Phase I Decision issued on August 3, 2022 (the “Phase I Decision”).

Requests for rehearing, reargument, or reconsideration (“RRR”) have been filed as to certain parts of the Phase I Decision by Public Service, Trial Staff, the Colorado Independent Energy Association, and Interwest Energy Alliance. Once the Commission reaches its decisions on the RRR requests, the Phase I Decision, as modified by any decision on RRR, will be the final decision of the Commission. The final decision can be appealed to district court (§ 40-6-115, C.R.S.) but, unless the final decision is stayed, Phase II of the proceeding will begin. The Phase II process is as follows:

1. Public Service will make any modifications required by the Commission’s Final Decision and get set up to conduct an all source competitive solicitation to fill the resource need approved in the Commission’s Phase I Decision. Then Public Service will issue a request for proposals.

1. Bidders will have 90 days within which to submit their bids in accordance with the detailed instructions in the RFP bid package. Submittals include competitive bids by independent power producers (“IPPs”) and utility-owned proposals.

1. Public Service will then have 120 days to review and evaluate the bids and submit to the Commission a report (the “120-Day Report”) presenting an evaluation of the proposed resources, based on the criteria established in the Phase I Decision regarding modeling inputs and assumptions to be used in developing optimized resource portfolios and the sensitivities that “re-price” optimized portfolios using alternative values for selected inputs and assumptions.

1. The Independent Evaluator (“IE”) files its own report within 30 days after the filing of the 120-Day Report. The IE Report contains an analysis of whether the utility conducted a fair bid solicitation and bid evaluation process.

1. Within 45 days of the filing of the 120-Day Report, the parties in the resource plan proceeding may file comments on the utility’s report and the IE report.

1. Within 60 days after the filing of the 120-Day Report, Public Service may file comments responding to the IE’s report and the parties comments.

1. Within 90 days after the filing of the 120-Day Report, the Commission shall issue a written decision approving, conditioning, modifying, or rejecting the utility’s preferred cost-effective resource plan, which decision shall establish the final cost-effective resource plan.

1. Public Service is then required to pursuant the final cost-effective resource plan either with a due diligence review and negotiation of purchase power agreements (PPAs) for IPP bids or with applications for certificates of public convenience and necessity (CPCNs) for utility-owned bids.

Modeling results in the Phase I proceeding, based upon generic resources, indicated the following resource acquisitions through 2030:

4. The Updated Settlement proposed that the resource needs in 2029 and 2030 would not be filled through the Phase II competitive solicitation. Instead, generic resources would be used for 2029 and 2030 in the modeling of the Phase II bids. The 2029 and 2030 resource needs would be filled through the Pueblo Just Transition Plan competitive solicitation (an interim ERP to be filed in 2024).

But Phase I modeling results do not predetermine the Phase II final cost-effective resource plan. The final resource plan will be based upon the proposals received in the competitive solicitation and, therefore, the types and sizes of resources acquired, and the cost and timing of those acquisitions will differ from the Phase I results that were based upon the modeling of generic resources.

The Phase I Decision is 186 pages long and resolves numerous issues including some very technical modeling issues. The following is a high-level summary of the main provisions of the Phase I Decision pertaining to specific types of facilities (coal, wind, solar, storage, and gas) and certain other major provisions of the Phase I Decision. Some of the decisions summarized below are subject to change in the Final Decision on the RRR requests.

Key ERP and CEP Proposals

As required by statute, 40-2-125.5(4), C.R.S., Public Service’s application included a clean energy plan to reduce the Company’s carbon dioxide emissions by a target of 80 percent by 2030 as compared to 2005 levels. The Application and the Phase I Decision distinguish between ERP resources and CEP resources. ERP resources are those resources needed to address the Company’s resource needs through 2030. CEP resources are those activities designed to achieve the 2030 carbon dioxide emissions reduction requirement of 80%.

The Phase I Decision approved the following proposals for early retirement of coal plants as part of the electric resource plan:

1. Early retirement of Craig in 2028
   Early retirement of Hayden 1 in 2028
   Early retirement of Hayden 2 in 2027

The Phase I decision approved the following activities as part of the clean energy plan:

1. Conversion of the Pawnee generating station from coal to natural gas no later than January 1, 2026

1. Early retirement of the Comanche Unit 3 coal plant no later than January 1, 2031 (with operations ratcheting down starting on January 1, 2025)

The Phase I Decision found that the coal action plan for Comanche Unit 3 not only helped achieve the clean energy target of 80 percent emissions reductions by 2030, but also makes progress towards the 2050 goal of 100 percent clean energy.

The Phase I Decision notes that several of the statutory findings required to approve a CEP cannot be made until Phase II. For example, the Commission must wait until Phase II to know the actions and investments required to fill the additional resource need for the CEP, the projected cost to implement the CEP, and the cost and rate impact of the 50% utility ownership target. But, the Commission states that the Phase I Decision provides the framework in which bids will be evaluated and selected, sets the Phase II assumptions regarding the treatment of the Public Service remaining coal-fired power plants, and ensures that the 120-Day Report contains the information required to make the statutory findings necessary to approve a CEP. The Commission does not anticipate another fully litigated hearing in Phase II. Instead, the Commission will address the necessary statutory findings in its Phase II decision after the typical Phase II process.

Timing of Resource Acquisitions

The Phase I Decision approved an Updated Settlement term providing that Public Service will allow bids with in-service dates as early as 2023, provided the bids are viable and the applicable construction timelines are reasonable.

Pueblo Just Transition Plan

The Comanche Unit 3 is located in Pueblo County, Colorado. It is the newest coal plant on the Public Service system and was expected to be in service until 2070. The early retirement of the Comanche Unit 3 has both job and tax impacts on the Pueblo community. The Updated Settlement included the following Pueblo Just Transition Plan:

1. While the upcoming Phase II solicitation will be for the resource acquisition period of 2021 through 2030, Public Service will not accept bids for or acquire any resources with in-service dates after December 31, 2028. Instead, the Company will use generic resources in 2029 and 2039 in its modeling for purpose of the final approved plan in Phase II. All 2029 and 2030 resource needs identified will be filled through the Pueblo Just Transition Plan solicitation which will use a resource acquisition period of 2029 through the end of 2031.

1. 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.

1. A separate Comanche 3 Just Transition Plan is 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 toward a carbon- free future.

1. 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.

1. 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.

The Phase I Decision approved the Pueblo Just Transitions Plan.

Best Value Employment Metrics.

The Updated Settlement included a multistep process for Phase II bid evaluation to ensure Best Value Employment Metrics (“BVEM”) as required by Colorado law. Bidders are required to include quantitative information with their bids concerning all BVEM requirements or, if the contracts for the project which is bid are not yet completed, the Bidders shall include the standards the Bidders include in their requests for proposals to be issued to subcontractors related to BVEM metrics, or if any of the quantitative information cannot be provided, bidders shall explain why as part of their bid package. A bid that incorporates a Project Labor Agreement will automatically be considered to meet threshold BVEM standards. Public Service will conduct an initial screen of BEM and disqualify bids that do not provide sufficient BVEM. Public Service will retain a labor economist to assist in scoring bids for BVEM. As part of its 120-day Report, the Company will provide a cumulative BVEM score for each portfolio presented. The Phase I Decision approved these terms.

Social Cost of Carbon to be Considered in Phase II Modeling

After Public Service filed its Application, the Colorado General Assembly adopted a statute requiring utilities to consider the social cost of carbon when determining the cost, benefit, or net present value in electric resource plans. § 40-3.2-106, C.R.S. In Decision No. C21-0246, the Commission stated that the 120-Day Report in Phase II will require (1) the utility to apply the cost of carbon dioxide emissions to the existing and new resources, (2) the presentation of net present value of revenue requirements that include the cost of carbon dioxide, and (3) the calculation of the net present value of the total cost of the carbon emissions. The Phase I Decision approved the Updated Settlement proposal to tie the social cost of carbon value and discount rate to the levels established by the Interagency Working Group Technical Support Document.

Energy and Capacity Rates for Solar + Storage Proposals

For solar + storage proposals (i.e., “hybrid resources”) submitted in Phase II, the Company proposed to offer an energy-only rate. Intervenors argued that there should be both an energy payment for the solar resource and a capacity payment for the storage resource. Public Service argued that an energy payment for the solar resources and a separate capacity payment for the storage resource would create finance lease and imputed debt issues which have a negative financial impact on the Company.

The Phase I Decision acknowledges that the finance lease and imputed debt issues articulated by Public Service are a real concern that needs to be considered but that energy-only payments for storage will significantly increase bid pricing and customer costs. To address these competing concerns, the Phase I Decision directed Public Service to follow the approach taken in New Mexico that allows solar + storage projects to be bid under two separate PPAs (one for the solar energy portion and the other for the storage portion). For the storage component, the bidder can bid either on an energy or capacity basis. If capacity is bid, however, the lease term is limited to 18 years to keep the lease terms under the 75% threshold for creating a capital lease (assuming a 25-year useful life).

The 18-year PPA term limitation for hybrid solar + storage projects is the subject of pending requests for RRR.

Standalone Battery Storage Bids.

Public Service asserted in its Application that PPAs for stand-alone battery storage could potentially be categorized as finance leases, and credit rating agencies view finance lease obligations in a more punitive manner, negatively impacting debt-to-capitalization ratios and putting stress on the Company’s credit Rate. To address this concern, the Model PPA for standalone storage states that Public Service is unwilling to be subject to the accounting treatment that results from the classification of a PPA as a finance lease and, therefore, requires that the PPA payments not exceed 90% of the value of the asset and limit the PPA term so as not to exceed 75% of the useful life of the asset (the “90/75 limitation”). The Phase I Decision prohibits the 90/75 limitation for standalone storage while, at the same time, acknowledging the Company’s concerns are legitimate and should not be ignored. The Decision states that the Commission has other tools at its disposal to holistically address the Company’s financial health.

This provision of the Phase I Decision is the subject of Public Service’s pending request for RRR.

Bids Proposing Interconnection at the Points of Delivery of Existing Generating Units Prior to Scheduled Retirement

The Phase I Decision directs Public Service to revise its RFP documents so that third-party bids can be proposed for interconnection to the same point of delivery as existing generation units prior to their scheduled retirement, subject to operating restrictions, special protection, or remedial action schemes to avoid potential overloads. These operating restrictions might increase the times in which the new project is curtailed and the Phase I Decision states that the generator will not be eligible for curtailment credits until the existing coal facility is retired and the new facility can alter its transmission service to firm. The Phase I Decision expressly states that this ruling in no way interferes with the property, land, water rights, and other broader private assets associated with Company-owned generation units and the decision is for purposes of evaluating bids in Phase II and does not resolve or opine on whether the Company’s Open Access Transmission Tariff (“OATT”) prohibits IPPs from using the existing transmission facilities for replacement generation.

These provisions of the Phase I Decision are included in Public Service’s request for RRR. Public Service explains the provisions of its OATT in detail, explains how it is reading the Commission’s Phase I directives (i.e., not to require the Company to violate the restrictions on generator replacement contained in the OATT nor other requirements of the OATT), and states that it is providing the information in the form of a RRR request to allow the Commission to determine if any modification to the Phase I Decision is necessary.

Not All Bids Advanced to Modeling

The Phase I Decision approves the Company’s plan to forward all Public Service bids to the modeling process. In contrast, IPP bids go through a screening process and not all are advanced to computer modeling.

Settlement Parties to be Reconvened to Make Changes to the Model PPAs to Reflect Changes in Tax Credits

The Phase I Decision approves the Updated Settlement provision that in the event of an extension or change in eligibility of the Federal Production Tax Credit/Investment Tax Credit program, the Settling Parties will be re-convened to attempt to make conforming changes to the model PPAs unanimously and take any other actions made necessary by the change in law. If unanimity cannot be achieved, the Company will bring such matters to the Commission for Resolution. The Inflation Reduction Act has triggered this provision of the Updated Settlement.

Modified Wind Committed Energy Requirements Approved

The Company’s Application proposed changes to the model PPA that establish committed energy requirements in which PPA wind projects would be penalized if they failed to deliver a certain percentage of energy. Public Service explained that the modifications were made to ensure that bidders can deliver on the representations they make in their bids and because it is becoming increasingly important that the energy promised from IPPs is the energy that will be delivered. The Updated Settlement modified the committed energy requirements for wind PPAs so that wind developers bear less weather risk. The Phase I Decision approved these modified provisions.

Use of Wind and Solar Integration Costs and Storage Credits to Be Discontinued

Public Service filed a Wind and Solar Integration Cost Study with its Application to evaluate three components of integration costs: 1) impacts on electric system regulation; 2) impacts on electric system operation given uncertainty in wind and solar forecast generation versus actual generation; and 3) impacts on the Company’s gas supply/storage system. Historically, integration costs have been used as an adder to the cost of wind and solar bids and as a credit to storage bids. Several parties objected to the continued used of integration costs. The Phase I Decision acknowledges that integration costs are real but concluded that continued use is discriminatory because there is no information in the record regarding integration costs associated with other resources such as thermal resources. Additionally, the Commission agreed with one party’s position that Public Service’s imminent participation in a EIM (energy imbalance market) would likely substantially reduce integration costs. (Public Service will be joining the Southwest Power Pool’s energy imbalance market and expects to do so in April 2023.) The Phase I Decision directs Public Service to discontinue the application of integration costs.

Phase I Decisions Concerning Gas-Fired Electric Generation

Currently, the primary technology to back up wind and solar resources is natural-gas fired generation. The Phase I Decision approves the Updated Settlement proposal that Public Service re-bid any existing gas units that are scheduled for retirement in the resource acquisition period so long as the retirement is not required pursuant to the Colorado State Implementation Plan and the unit can reasonably be expected to perform in a manner that balances the Company’s system. The Phase I Decision also approved the following provisions from the Company’s Application regarding gas units bid into the Phase II solicitation but with the modifications noted below:

• Bidders of new gas units will be encouraged to submit bids with an option for the unit to burn a minimum of 30% hydrogen. This is a clean energy plan proposal to make progress toward the 2050 target of 100% clean energy. In the Phase I Decision, the Commission added that bidders are encouraged, on a voluntary basis, to also report the maximum hydrogen mixing capability of their units in order to provide information regarding where the market is at and whether it provides a pathway to achieve the state’s 100% clean energy target by 2050.
• The Company must be able to remotely start simple cycle facilities at all hours.
• Any new, repowered, or rebid generating units within a plant must be able to start simultaneously.
• A unit must be able to start on either natural gas or fuel oil at the Company’s election and switch between fuel oil and gas without interruption.
• Simple-cycle generators must be capable of starting within ten minutes (fast start capability).
• Bids must include a plan to have fuel and any ancillary product on site necessary to permit the facility to run continuously for a minimum number of hours at maximum load on alternative fuel, or have firm gas transportation contracts that could serve as a substitute for the requirement to have an alternative such as fuel oil on-site. In its Application, Public Service proposed that the minimum run time be 72 hours but at hearing, Public Service testified that this 72-hour period reasonably could be extended to four or five days given what happened during Winter Storm Uri. In the Phase I Decision the Commission concluded that the must run capability on alternative fuel should be at least five days.

The Phase I Decision requires Public Service to be flexible as to the application of these requirements to existing gas units that are re-bid into the upcoming competitive solicitation. The Decision states that, “the Company should use good judgment when it evaluates the rebid of existing gas units to enable the continued use of these units over the construction of new units wherever possible.” The preference for existing gas units over new gas units is to reduce the risk of stranded costs for new units in the event alternative technologies, such as utility scale storage, are developed in the future that can replace gas-fired electric generation as the primary backup resource for wind and solar resources.

The Phase I Decision approves a provision in the Updated Settlement that Public Service would include in its Phase II modeling a “No New Natural Gas Build Portfolio.” The modeling would evaluate only existing rebid Public Service facilities and proposals for extension of third-party PPAs. The Commission acknowledged the language in the Updated Settlement that this portfolio may be infeasible or fail the Company’s reliability check. In such event, the Phase I Decision requires the Company to report this in its 120-Report.

Social Cost of Methane

Several parties argued in the Phase I proceeding that the Phase II modeling should evaluate the social cost of methane. A new statute, 40-3.2-106(1), C.R.S., adopted after Public Service filed its Application, requires the Commission to consider the social cost of carbon dioxide emissions and the social cost of methane. In the Phase I Decision, the Commission concluded that it had the authority to consider the social cost of methane under its broad “public interest” authority to consider reductions in carbon dioxide and other emissions even without application of the new statute.

The Commission directed Public Service to create a social cost of methane sensitivity for the Phase II preferred portfolio that shows the net present value of the revenue requirement (NPVRR) of the social cost of methane. The Company was directed to use the EPA emissions factors to calculate downstream methane emissions (for the combustion of fossil fuels). For the upstream emissions that occur during the production, processing, transportation, and storage of natural gas, Public Service was directed to craft a methodology using an emission factor of between 1% and 0.25%. The Phase I Decision sets the social cost of methane for at least $1,756 per short ton of methane but states that the ultimate SCM value and discount rate shall be tied to the most recent value and discount rate established by the Interagency Working Group Technical Support Document. Note that this sensitivity is limited to gas-fired electric generating resources. Upstream emissions associated with coal mining, and the mining, manufacturing, transportation, and construction of renewable resources are not included in the Phase II modeling.

Responsibly Sourced Gas

In its Application, Public Service asked for party input on the costs and benefits of pursuing, in the future, obtaining natural gas associated with new gas-fired electric generation from “certified” or “responsibly-sourced” natural gas sources (“RSG”). However, Public Service was not proposing a responsibly sourced gas requirement in the proceeding or seeking any Commission approvals relating to responsibly sourced gas. One party requested that the Commission hold that Public Service should not require ratepayers to pay a premium price for responsibly sourced gas. In the Phase I Decision, the Commission declined to make any broad pronouncements regarding RSG and said it would defer expressing an opinion until an appropriate future proceeding in which the Commission is being asked to adjudicate an issue.

Section 123 Resources

Section 123 resources are defined to mean “new energy technology or demonstration projects, including new clean energy or energy-efficient technologies” under § 40-2-123(1)(a), C.R.S. and § 40-2- 123(1)(c), C.R.S., and Integrated Gasification Combined Cycle projects under § 40-2-123(2), C.R.S. The Phase I Decision recognized that for a resource bid into Phase II to be considered a Section 123 resources, it must be new, innovative, not commercialized technology, and provide unique, scalable, and beneficiation attributes as to future costs, emissions reduction, or reliability benefits. Standalone wind, solar, or lithium-ion based battery storage of any duration and any combination of those technologies together with other resources are not Section 123 Resources.

Public Service was directed to group Section 123 bids by technology and cost and forward them to modeling for portfolio re-optimization and presentation in the 120-Day Report with the least-cost Section 123 bids by technology “locked in.”

Pre-Construction Development Assets

The Phase I Decision states that, as compared to prior electric resource plans, this Phase I proceeding and record show “perhaps an unprecedented amount of uncertainty.” As examples, the Decision points to uncertainty regarding peak demand and energy forecasts; the potential impact of changing climate patterns and extremes during peak times that might reduce hydroelectric output, decrease the availability of thermal units and their fuel, or materially limit generation from solar and wind resources; and other factors such as supply chain disruptions, inflation, rising interest rates, and solar tariffs. The Decision found that, “material risk remains that Public Service’s system may need more capacity sooner because of extreme weather, extended unit unavailability, or an inability to build some of the gas combined cycle (CT) resources selected out of Phase II. Under any of these circumstances, it could take a year to run an acquisition process and at least three years to build additional CTs.”

As a means to address planning uncertainty and unexpected circumstances, the Phase I Decision requests that the Company explore acquiring pre-construction development assets for wind, solar, storage, and CT resources but avoid building the projects now. Instead, the Company would finish development of these pre-construction assets over time and then potentially bid these projects into the all-source 2024 Pueblo Just Transition solicitations. The Phase I Decision also encourages Public Service to provide, concurrent with the 120-Day Report, updated contingency planning proposals that would include any bids for preconstruction development assets. The pre-construction development assets could be either Company-owned or IPP-owned.

The provisions of the Phase I Decision regarding pre-construction development assets are the subject of pending requests for RRR.

Next ERP

The Phase I Decision approves the Updated Settlement proposal that the next regularly-scheduled ERP shall be filed no later than October 31, 2026. (The Pueblo Just Transition Plan is an Interim ERP.) The Decision states that Public Service may request a variance if future circumstances warrant a change.

Not There Yet – Other Items in the Pending Requests for RRR

The summary above notes which items are the subject of the pending RRR requests. But, the RRR requests also concern other provisions of the Phase I Decision not summarized above including:

1. A Deferred Tax Asset forecast the Commission directed Public Service to submit after working with Staff to evaluate alternative DTA modeling methods. The concern is Public Service-owned facilities for which Public Service was not, under the prior production/incentive tax credits, able to take the credits. The Trial Staff is seeking in its request for RRR to provide for the exchange of workpapers and other explanations and for a process to resolve irreconcilable disagreements. Public Service, on the other hand, states in its request for RRR that this issue may be resolved by provisions of the Inflation Reduction Act.

1. The Updated Settlement Agreement provides for a performance incentive mechanism (“PIM”) stakeholder process. Public Service requests in its RRR that the Commission make certain modifications to its Phase I Decision directives pertaining to this process.

1. Public Service requests a modification to the Phase I Decision as to cost recovery mechanism for prudently incurred, investigatory costs associated with the Unaweep Project, a potential pumped storage hydropower project on the Western Slope.

1. Public Service requests modification to the Phase I Decision requirements concerning the planning reserve margin study to be submitted as part of the Pueblo Just Transitions Plan. Specifically, Public Service requests modifications to the requirement for it to model all WECC regions.

1. The Phase I Decision required Public Service to report certain information regarding its water rights. Public Service has proposed in its request for RRR two options for how it might do the reporting and asks that the requirement to value water rights as part of the reporting be removed. Public Service notes that historic consumptive use is the driver of any valuation exercise and this is a nuanced, fact-drive analysis, and is most often the root of contested litigation in Colorado’s Water Courts.

1. The Phase I decision deferred decision on two renewable energy standard adjustment (RESA) issues. Public Service requests in RRR that the Commission to construe the currently pending Proceeding No. 21A-625EG as the appropriate RES plan proceeding for resolution of these issues. Public Service also puts the Commission on notice in its request for RRR that it would like to implement the CEP cost recovery provisions (the “CEPR”) as soon as possible after the Phase II decision and no later than January 1, 2024.

1. In its request for RRR, Public Service seeks Commission approval that it is appropriate to account for the passage of the Inflation Reduction Act in its generic resource costs presented in the inputs and assumptions filing to be made prior to commencing the Phase II competitive solicitation.

1. Public Service seeks clarification from the Commission regarding the authorization given to it in the Phase I Decision to place coal units into temporary economic shutdown outside of a rate case. Public Service is asking whether the Commission anticipates questioning, or allowing intervenors to question, cost recovery for units that were in temporary economic shutdown, stating that, if so, the Company would need to take that into account in its decision-making process.

1. Public Service seeks confirmation that the project level analysis for transmission costs it is required to develop on the truncated 120-Day Report timeline is to be done in a manner similar to previous presentations where the Company will use its best efforts to categorize general areas of anticipated transmission costs unknown at the time, with the understanding that additive transmission studies are necessary to determine the full extent of the transmission investment necessary to implement a portfolio.

1. The Phase I Decision approved a provision of the Updated Settlement concerning the use of the social cost of carbon in dispatch or commitment of resources pending FERC approval. Public Service seeks confirmation that if market rules permit it to continuing using the social cost of carbon in the dispatch or commitment of resources, assuming FERC approval of any such approach, it is required to continue using the SCC value in the dispatch or commitment of resources and that such use is consistent with the Phase I Decision.

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