Consideration of Greenhouse Gas Emissions in Natural Gas Infrastructure Project Reviews

Federal RegisterMar 11, 2022

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

[Docket No. PL21-3-000]

Consideration of Greenhouse Gas Emissions in Natural Gas Infrastructure Project Reviews

AGENCY:

Federal Energy Regulatory Commission.

ACTION:

Interim policy statement.

SUMMARY:

This interim policy statement describes Commission procedures for evaluating climate impacts under NEPA and describes how the Commission will integrate climate considerations into its public interest determinations under the NGA.

DATES:

Public comments are due on or before April 4, 2022. Comments on the information collection are due May 10, 2022.

ADDRESSES:

Comments, identified by docket number, may be filed electronically at

http://www.ferc.gov

in acceptable native applications and print-to-PDF, but not in Scanned or picture format. For those unable to file electronically, comments may be filed by mail or hand-delivery to: Federal Energy Regulatory Commission, Secretary of the Commission, 888 First Street NE, Washington, DC 20426. The Comment Procedures section of this document contains more detailed filing procedures.

FOR FURTHER INFORMATION CONTACT:

Karin Larson (Legal Information), Office of the General Counsel, 888 First Street NE, Washington, DC 20426, (202) 502-8236,

Karin.Larson@ferc.gov

Eric Tomasi (Technical Information), Office of Energy Projects, Federal Energy Regulatory Commission, 888 First Street NE, Washington, DC 20426, (202) 502-8097,

Eric.Tomasi@ferc.gov

SUPPLEMENTARY INFORMATION:

1. The Commission is issuing this interim policy statement to explain how the Commission will assess the impacts of natural gas infrastructure projects on climate change in its reviews under the National Environmental Policy Act (NEPA) and the Natural Gas Act (NGA). We seek comment on all aspects of the interim policy statement, including, in particular, on the approach to assessing the significance of the proposed project's contribution to climate change. Although the guidance contained herein is subject to revision based on the record developed in this proceeding, we will begin applying the framework established in this policy statement in the interim. Doing so will allow the Commission to evaluate and act on pending applications under sections 3 and 7 of the NGA without undue delay and with an eye toward greater certainty and predictability for all stakeholders.

I. Introduction

2. Climate change poses a severe threat to the nation's security, economy, environment, and to the health of individual citizens. Human-made greenhouse gas (GHG) emissions, including carbon dioxide and methane, are the primary cause of climate change.

GHG emissions are released in large quantities through the production, transportation, and consumption of natural gas. Accordingly, to fulfill its statutory responsibilities, it is critical that the Commission consider and document how its authorization of infrastructure projects under the NGA, particularly natural gas transportation facilities, will affect emissions of GHGs.

Intergovernmental Panel on Climate Change, United Nations,

Summary for Policymakers

of Climate Change 2021: The Physical Science Basis SPM-5 (Valerie Masson-Delmotte et al. eds.) (2021),

https://www.ipcc.ch/report/ar6/wg1/downloads/report/IPCC_AR6_WGI_SPM.pdf

(IPCC Report).

See Sierra Club

FERC,

867 F.3d 1357, 1374 (D.C. Cir. 2017) (

Sabal Trail

) (requiring the Commission to consider the reasonably foreseeable GHG emissions resulting from natural gas projects).

3. This policy statement describes Commission procedures for evaluating climate impacts under NEPA, both those caused by a project's contribution to climate change and the impacts of climate change on the project, and describes how the Commission will integrate climate considerations into its public interest determinations under the NGA. For purposes of assessing the appropriate level of NEPA review, Commission staff will apply the 100% utilization or “full burn” rate for the proposed project's emissions to determine whether to prepare an Environmental Impact Statement (EIS) or an environmental assessment (EA). Commission staff will proceed with the preparation of an EIS, if the proposed project may result in 100,000 metric tons per year of CO

e or more.

As further described below, the Commission believes this estimate is appropriate because it captures Commission projects that may result in incremental GHG emissions that may have a significant effect upon the human environment.

This approach is consistent with the overall goal of NEPA to require a “hard look” at adverse environmental impacts and assess whether those can be minimized or avoided.

To appropriately assess possible mitigation, as further explained below, the Commission will determine a project's reasonably foreseeable GHG emissions based on a projection of the amount of capacity that will be actually used (projected utilization rate), as opposed to assuming 100% utilization, and any other factors impacting the quantification of project emissions. The Commission's NEPA analysis will examine any proposed measures to reduce reasonably foreseeable emissions.

Carbon dioxide equivalent is the combination of the emissions that contribute to climate change adjusted using each pollutant's global warming potential. This allows the Commission to aggregate all GHG emissions into a single value that accounts for each chemical's specific potential to trap heat in the atmosphere.

See, e.g., Grand Canyon Trust

FAA,

290 F.3d 339, 340 (D.C. Cir. 2002) (“If

any

`significant' environmental impacts might result from the proposed agency action[,] then an EIS must be prepared

before

agency action is taken.” (quoting

Sierra Club

Peterson,

717 F.2d 1409, 1415 (D.C. Cir. 1983)));

Found. for N. Am. Wild Sheep

U.S. Dep't of Agr.,

681 F.2d 1172, 1178 (9th Cir. 1982) (“If substantial questions are raised whether a project may have a significant effect upon the human environment, an EIS must be prepared.”).

See

42 U.S.C. 4331(a); 4332(c).

4. When considering under the NGA whether a project is in the public interest, the Commission considers a project's impacts on climate change, and, accordingly, will consider proposals by the project sponsor to mitigate all or a portion of the project's climate change impacts, and the Commission may condition its authorization on the project sponsor further mitigating those impacts.

5. This policy statement does not establish binding rules and is intended to explain how the Commission will consider these issues when they arise.

Commissioner Danly's dissent claims that today's interim policy statement is “a substantive, binding rule that is subject to judicial review.” Danly Dissent at P 46. This interim document is intended to provide all interested entities with guidance as to how the Commission will approach application under NGA sections 3 and 7. It does not “impose[] an obligation, den[y] a right, or fix[] some legal relationship.”

Reliable Automatic Sprinkler Co.

Consumer Prod. Safety Comm'n,

324 F.3d 726, 731 (D.C. Cir. 2003). Parties that disagree with the approach outlined in the statement retain their full rights to litigate their concerns in any individual proceeding.

Cf. id.

(“Final agency action `marks the consummation of the agency's decisionmaking process' and is `one by which rights or obligations have been determined, or from which legal consequences will flow.') (quoting

Bennett

Spear,

520 U.S. 154, 178 (1997)). In addition, Commissioner Danly speculates that “no project sponsor will believe that mitigation is optional or that submitting an application exceeding the Interim Policy Statement's 100,000 tpy threshold without a mitigation proposal would be anything other than a waste of time and money.” Danly Dissent PP 46-47. In response, we note only that the Commission will consider mitigation on a case-by-case basis and that we have not suggested that GHG emissions must be mitigated to insignificant levels in order for us to conclude that a proposed

project is required by the public convenience and necessity or consistent with the public interest.

II. Background

A. GHG Emissions and Climate Change

6. Climate change is the variation in the Earth's climate (including temperature, precipitation, humidity, wind, and other meteorological variables) over time. Climate change is driven by accumulation of GHGs in the atmosphere due to the increased consumption of fossil fuels (

e.g.,

coal, petroleum, and natural gas) since the early beginnings of the industrial age and accelerating in the mid- to late-20th century.

The GHGs produced by fossil-fuel combustion are carbon dioxide, methane, and nitrous oxide.

IPCC Report at SPM-5. Other forces contribute to climate change, such as agriculture, forest clearing, and other anthropogenically driven sources.

7. In 2017 and 2018, the U.S. Global Change Research Program

issued its Climate Science Special Report: Fourth National Climate Assessment, Volumes I and II.

This report and the recently released report by the Intergovernmental Panel on Climate Change, Climate Change 2021: The Physical Science Basis, state that climate change has resulted in a wide range of impacts across every region of the country and the globe. Those impacts extend beyond atmospheric climate change and include changes to water resources, agriculture, ecosystems, human health, and ocean systems.

According to the Fourth Assessment Report, the United States and the world are warming, global sea level is rising and oceans are acidifying, and certain weather events are becoming more frequent and more severe.

These impacts have accelerated throughout the end of the 20th century and into the 21st century.

The U.S. Global Change Research Program is the leading U.S. scientific body on climate change. It comprises representatives from 13 federal departments and agencies and issues reports every 4 years that describe the state of the science relating to climate change and the effects of climate change on different regions of the United States and on various societal and environmental sectors, such as water resources, agriculture, energy use, and human health.

U.S. Global Change Research Program, Climate Science Special Report, Fourth National Climate Assessment | Volume I (Donald J. Wuebbles et al. eds) (2017),

https://science2017.globalchange.gov/downloads/CSSR2017_FullReport.pdf

; U.S. Global Change Research Program, Fourth National Climate Assessment, Volume II Impacts, Risks, and Adaptation in the United States (David Reidmiller et al. eds.) (2018),

https://nca2018.globalchange.gov/downloads/NCA4_2018_FullReport.pdf

(USGCRP Report Volume II).

IPCC Report at SPM-5 to SPM-10.

USGCRP Report Volume II at 73-75.

See, e.g.,

USGCRP Report Volume II at 99 (describing accelerating flooding rates in Atlantic and Gulf Coast cities).

B. Council on Environmental Quality Guidance on Climate Change

8. In 2010, the Council on Environmental Quality (CEQ) issued its first draft guidance on how federal agencies can consider the effects of GHG emissions and climate change under NEPA.

CEQ revised the draft guidance in 2014,

and issued final guidance in 2016.

Throughout the guidance's evolution, CEQ advised agencies to quantify GHG emissions and to consider both the extent to which a proposed project's GHG emissions would contribute to climate change and how a changing climate may impact the proposed project. The 2016 guidance, however, explicitly declined to establish a quantity or threshold of GHGs for determining whether a proposed project will have a significant impact on climate.

CEQ,

Draft NEPA Guidance on Consideration of the Effects of Climate Change and Greenhouse Gas Emissions

(Feb. 18, 2010),

https://ceq.doe.gov/docs/ceq-regulations-and-guidance/20100218-nepa-consideration-effects-ghg-draft-guidance.pdf

Revised Draft Guidance for Federal Departments and Agencies on Consideration of Greenhouse Gas Emissions and the Effects of Climate Change in NEPA Reviews, 79 FR 77802 (Dec. 24, 2014).

CEQ,

Final Guidance for Federal Departments and Agencies on Consideration of Greenhouse Gas Emissions and the Effects of Climate Change in National Environmental Policy Act Reviews

(Aug. 1, 2016),

https://ceq.doe.gov/docs/ceq-regulations-and-guidance/nepa_final_ghg_guidance.pdf

(2016 CEQ Guidance).

2016 CEQ Guidance at 9-10 (“This guidance does not establish any particular quantity of GHG emissions as `significantly' affecting the quality of the human environment or give greater consideration to the effects of GHG emissions and climate change over other effects on the human environment.”).

9. CEQ rescinded the 2016 guidance in April 2017, as directed by Executive Order 13783

Promoting Energy Independence and Economic Growth,

and issued revised draft guidance in June 2019.

In January 2021, Executive Order 13990

Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis

revoked Executive Order 13783 and directed CEQ to rescind the 2019 draft guidance and to review, revise, and update the 2016 guidance.

CEQ has not yet issued an update to the 2016 guidance, but, in the interim, has directed agencies to consider all available tools and resources, including the 2016 guidance, in assessing GHG emissions and the climate change effects of proposed actions.

Exec. Order No. 13783, 82 FR 16576 (Apr. 5, 2017).

Draft National Environmental Policy Act Guidance on Consideration of Greenhouse Gas Emissions, 84 FR 30097 (June 26, 2019).

Exec. Order No. 13990, 86 FR 7037 (Jan. 20, 2021).

Notice of Rescission of Draft Guidance, 86 FR 10252 (Feb. 19, 2021).

C. Previous Commission Policy on Consideration of Climate Change Under NEPA

10. Commission staff has addressed climate change in some fashion in its NEPA documents for at least a decade.

Commission staff's NEPA documents have included direct GHG emission estimates from project construction (

e.g.,

tailpipe emissions from construction equipment) and/or operation (

e.g.,

fuel combustion at compressor stations and gas venting and leaks).

Starting in late 2016, the Commission began to conservatively estimate indirect downstream GHG emissions by assuming full combustion of the maximum annual volume of gas that could be transported by the project.

For indirect upstream, production-related GHG emissions, Commission orders during that time period relied on Department of Energy studies to calculate broad estimates.

For upstream impacts, the Commission generally indicated that these analyses were not required by NEPA because the Commission lacked detailed information about the precise source of the gas to be transported, but provided estimates for informational purposes.

For details on GHG analysis in the Commission's NEPA documents through April 2018, see

Certification of New Interstate Natural Gas Facilities,

83 FR 18020, 163 FERC ¶ 61,042, at PP 44-50 (2018) (2018 NOI).

See, e.g.,

Environmental Assessment for the Philadelphia Lateral Expansion Project, Docket No. CP11-508-000, at 24 (Jan. 18, 2012) (construction emissions); Environmental Assessment for the Minisink Compressor Project, Docket No. CP11-515-000, at 29 (Feb. 29, 2012) (operation emissions).

See, e.g., Columbia Gas Transmission, LLC,

158 FERC ¶ 61,046, at P 120 (2017);

Tex. E. Transmission, LP,

157 FERC ¶ 61,223, at P 41 (2016),

reh'g granted,

161 FERC ¶ 61,226 (2017).

See, e.g., Columbia Gas Transmission, LLC,

158 FERC ¶ 61,046 at PP 116-119.

With respect to upstream emissions, the D.C. Circuit subsequently noted that the Commission does not violate NEPA in not considering upstream GHG emissions where there is no evidence to predict the number and location of additional wells that would be drilled as a result of a project.

Birckhead

FERC,

925 F.3d 510, 518 (D.C. Cir. 2019) (

Birckhead

11. In 2017, the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit) in

Sierra Club

FERC

(

Sabal Trail

)

found that downstream GHG emissions were an indirect effect of the Sabal Trail pipeline project and required the Commission to give a quantitative estimate of the downstream GHG emissions resulting from the burning of the natural gas to be

transported by the pipeline or explain why the Commission could not do so, and to discuss the significance of these emissions.

On remand, the Commission compared the estimated downstream GHG emissions from the project to state and national GHG emission inventories.

However, the Commission concluded that it could not determine whether those downstream GHG emissions were significant and rejected the use of the Social Cost of Carbon (SCC) tool to inform the Commission's analysis.

867 F.3d 1357.

Id.

at 1374.

Fla. Se. Connection, LLC,

164 FERC ¶ 61,099, at P 5 (2018).

Id.

No party petitioned for judicial review of the Commission's determination on remand.

12. In 2018, the Commission stated in

Dominion Transmission, Inc.

that end use consumption of gas and upstream production of gas were generally not reasonably foreseeable or causally related to the project (no party had identified the specific end use of the gas) and thus the Commission was not required to consider upstream or downstream emissions as indirect impacts under NEPA.

The Commission stated it would continue to “analyze upstream and downstream environmental effects when those effects are sufficiently causally connected to and are reasonably foreseeable effects of the proposed action.”

The Commission reiterated that without an accepted methodology it could not find whether a particular quantity of GHG emissions was significant.

163 FERC ¶ 61,128 (2018),

pet. dismissed, Otsego 2000

FERC,

767 F.App'x 19 (D.C. Cir. 2019) (unpublished opinion).

Id.

PP 41-44, 61-62.

Id.

P 44;

see also

INGAA Technical Conference Comments at 14 (adding that NEPA's requirements would exclude downstream emissions occurring after a “long and attenuated chain of intermediate causal factors, as when natural gas is transported to an interconnect for further shipment on the interstate grid, eventually reaching end-use consumers only through a long intermediate path”).

941 F.3d 1288 (11th Cir. 2019) (

Center for Biological Diversity

Id.

at 1300 (citing

Pub. Citizen,

541 U.S. 752 and

Metro. Edison Co.,

460 U.S. 766).

38. Given that data show that the vast majority of consumed gas is ultimately combusted,

100

there appears to be a

substantial likelihood of GHG emissions from the end-use combustion of transported gas as a result of a natural gas project proposed under NGA section 7.

101

However, as contemplated by the court in

Birckhead,

there may be circumstances where downstream emissions are not a foreseeable effect of an authorized project, and the court stated that each project must be analyzed on a case-by-case basis.

102

Accordingly, project sponsors may submit any evidence they believe indicates that downstream emissions are not a reasonably foreseeable effect of a proposed project.

100

U.S. Energy Info. Admin.,

December 2021 Monthly Energy Review

24, 101 (2021) (reporting

that, in 2020, 1,036 Bcf of natural gas had a non-combustion use compared to 30,476 Bcf of total consumption),

https://www.eia.gov/totalenergy/data/monthly/pdf/mer.pdf

;

see also

Jayni Hein et al., Institute for Policy Integrity,

Pipeline Approvals and Greenhouse Gas Emissions

25 (2019) (explaining that, in 2017, 97% of all natural gas consumed was combusted).

101

See Birckhead,

925 F.3d at 518;

Sabal Trail,

867 F.3d at 1371-72.

102

Birckhead,

925 F.3d at 518-19 (rejecting, in

dicta,

that downstream emissions are always a foreseeable effect of a proposed certificate project).

39. We disagree with commenters' assertions that

Public Citizen

prohibits the Commission from considering downstream GHG emissions. The question is not whether the Commission has regulatory authority over downstream emissions. Rather, as the

Sabal Trail

court reasoned in applying

Public Citizen,

the Commission “has no obligation to gather or consider environmental information [only] if it has no statutory authority

to act on that information.

”

103

Because the Commission can reject a section 7 certificate based on the project's environmental impacts, including GHG emissions, the court held that the Commission was required to consider downstream emissions resulting from the Sabal Trail project's construction.

104

For section 7 projects—unlike section 3 projects, described below—there is no independent decision, such as the DOE authorization critical in

Freeport,

to “break the NEPA causal” chain.

105

Accordingly, the Commission's authorization for section 7 projects is a “legally relevant cause” of the emissions, meeting

Public Citizen'

s direction that “NEPA requires `a reasonably close causal relationship' between the environmental effect and the alleged cause,” analogous to the “familiar doctrine of proximate cause from tort law.”

106

103

Sabal Trail,

867 F.3d at 1372-73 (emphasis in original) (explaining

Pub. Citizen,

541 U.S. 752).

104

See id.

at 1373 (“Because FERC could deny a pipeline certificate on the ground that the pipeline would be too harmful to the environment, the agency is a `legally relevant cause' of the direct and indirect environmental effects of pipelines it approves.” (quoting

Freeport,

827 F.3d at 47).

105

Freeport,

827 F.3d at 47.

106

Pub. Citizen,

541 U.S. at 767 (quoting

Metro. Edison Co.,

460 U.S. at 774).

40. The Commission finds this and subsequent direction from the D.C. Circuit more instructive than

Center for Biological Diversity,

which determined that a specific effect was too tenuous to be considered in analysis of a U.S. Army Corps of Engineers discharge permit for mining activities under the Clean Water Act.

107

See Center for Biological Diversity,

941 F.3d at 1292 (describing whether the U.S. Army Corps of Engineers legally declined to address, in issuing discharge permits for phosphate mining, the effects of a radioactive byproduct of fertilizer production (phosphogypsum), where the phosphogypsum is neither a byproduct of dredging and filling or phosphate mining or beneficiation). The court criticized the reasoning in

Sabal Trail

but also observed that the “causal relationship between the agency action and the putative downstream effect was much closer [in

Sabal Trail

] than it is here” and that the Commission's scope of statutory authority is “much broader” than that of the U.S. Army Corps of Engineers.

Id.

at 1299-1300.

41. However, for proposed export projects under NGA section 3, the Commission will not consider downstream GHG emissions an effect requiring analysis under NEPA regulations. The Department of Energy, not the Commission, has sole authority to license and consider the environmental impacts of the export of any natural gas.

108

As courts have explained, the Commission need not consider the effects of downstream transportation, consumption, or combustion of exported gas because the Department of Energy's “independent decision to allow exports . . . breaks the NEPA causal chain and absolves the Commission of responsibility to include [these considerations] in its NEPA analysis.”

109

108

Freeport,

827 F.3d at 47 (holding that the Commission does not have to address the indirect effects of the anticipated export of natural gas because the Department of Energy, not the Commission, has sole authority to license and consider the environmental impacts of the export of any natural gas going through LNG facilities);

Freeport,

827 F.3d at 62-63 (same);

EarthReports, Inc.

FERC,

828 F.3d at 956 (same);

Sabal Trail,

867 F.3d at 1372 (explaining

Freeport

109

Freeport,

827 F.3d at 48.

c. Upstream Emissions

42. Some commenters state that the Commission must consider the upstream GHG emissions of natural gas projects, including fugitive emissions from production,

110

to assess the project's total impact on climate change.

111

Other commenters argue that upstream emissions are not a reasonably foreseeable effect of a natural gas transportation project, and therefore should not be considered by the Commission.

112

Some commenters focus on how to obtain sufficient information to account for upstream GHG emissions. For example, EPA recommends that the Commission require project sponsors to provide available information on reasonably foreseeable induced production demand. EPA states that environmental documents under NEPA should disclose this information as well as items such as the proposal's regionally known hydrocarbon accumulations and a decline curve analysis to allow for appropriate regional and local impact analysis.

113

110

See, e.g.,

Egan Millard 2021 Comments at 3; Shayna Gleason 2021 Comments at 2.

111

See, e.g.,

Institute for Policy Integrity at New York University School of Law (Policy Integrity) Technical Conference Comments at 17; Food and Water Watch 2021 Comments at 1; New Jersey Conservation Foundation 2021 Comments at 19.

112

See, e.g.,

Boardwalk Technical Conference Comments at 21; Enbridge Technical Conference Comments at 11, 25-26; TC Energy Corporation (TC Energy) Technical Conference Comments at 5; Williams Technical Conference Comments at 4; INGAA 2021 Comments at 56-57; Williams 2021 Comments at 37-38.

113

EPA 2021 Comments at 5.

43. In various NGA section 7 proceedings, the Commission has considered upstream emissions on a case-by-case basis—sometimes acknowledging it is difficult to quantify upstream emissions due to several unknown factors, including the location of the supply source and whether transported gas will come from new or existing production.

114

The Commission will continue to consider on a case-by-case basis whether the environmental effects resulting from natural gas production are either likely caused by a proposed NGA section 7 project or reasonably foreseeable consequences of our approval of such projects. To the extent known, project sponsors are encouraged to submit information on the reasonably foreseeable upstream impacts caused by the project or an explanation as to why there are none for Commission consideration.

114

See Birckhead,

925 F.3d at 516-18.

See, e.g., Double E Pipeline, LLC,

173 FERC ¶ 61,074, at P 97 (2020);

Cent. N.Y. Oil & Gas Co., LLC,

137 FERC ¶ 61,121, at PP 81-101 (2011),

order on reh'g,

138 FERC ¶ 61,104, at PP 33-49 (2012),

petition for review dismissed sub nom., Coal. for Responsible Growth

FERC,

485 F.App'x 472, 474-75 (2d Cir. 2012) (unpublished opinion);

see also

Boardwalk Technical Conference Comments at 3, 23; Williams Technical Conference Comments at 7. API, on the other hand, asserts that use of utilization estimates or emissions data forces the Commission to pick winners among competing pipeline projects and asserts that such decisions are best made by market forces after the Commission authorizes a project. API Technical Conference Comments at 3-4.

48. Conversely, New Jersey Conservation Foundation and others argue the Commission must calculate direct, downstream, and upstream GHG emissions by assuming the maximum authorized operating conditions, unless, some add, the project sponsor can demonstrate otherwise.

121

Further, other commenters propose their own methods of how to calculate the downstream emissions of a proposed project.

122

New Jersey Conservation Foundation urges the Commission to recommend or require the use of specified emissions factors to calculate project emissions.

123

Some commenters argue that the Commission must, beyond asking project sponsors, require certain information to be provided, conduct independent research, or otherwise compile missing information.

124

Dr. Susan F. Tierney states that the Commission should articulate a default methodology, set of assumptions, and sources of data (suggesting multiple sources including data from the U.S. Department of Energy's National Energy Technology Laboratory's 2019 life-cycle estimates of GHG emissions for the natural gas supply chain) to establish a default maximum emissions rate, which could then be supplemented by an applicant's own estimate or an intervenor's alternative estimate.

125

121

See, e.g.,

New Jersey Conservation Foundation 2021 Comments at 21-22; Public Interest Organizations 2018 Comments at 91; Washington State Department of Commerce and Washington State Department of Ecology 2018 Comments at 6. Public Interest Organizations' 2018 comments represent 63 entities including Natural Resources Defense Council.

122

See, e.g.,

Charles River Associates 2021 Comments at 6-8 (proposing a regional analysis to estimate downstream emissions of a gas project).

123

New Jersey Conservation Foundation 2021 Comments at 22.

124

See, e.g.,

Berkshire Environmental Action Team 2021 Comments at 3; North Carolina Department of Environmental Quality 2018 Comments at 5-8.

125

Dr. Susan F. Tierney, Senior Advisor with the Analysis Group, Inc., was a panelist at the GHG Technical Conference on Panel 1. Dr. Susan F. Tierney Technical Conference Statement at 4-10. The applicant could supplement its estimate with an alternative estimate, and intervenors could also submit estimates.

a. Projected Utilization Rate

49. In previous environmental documents and certificate orders, the Commission has disclosed a project's operational emissions

126

and estimates

of downstream emissions

127

by assuming a 100% utilization rate estimate of the project (

e.g.,

the maximum capacity is transported 365 days per year, 24 hours a day and fully combusted downstream). This represents the maximum potential downstream GHG emissions. However, most projects do not operate at 100% utilization at all times. In fact, many projects are designed to address peak demand. For example, traditionally, in the Northeast, demand for gas is highest in the winter months, resulting in high utilization rates during those months due to heating needs, but lower in the summer, resulting in low annual utilization rates.

128

126

See

Environmental Assessment for the Lake City 1st Branch Line Abandonment and Capacity Replacement Project, Docket No. CP20-504-000, at 51-53 (Feb. 2021);

see also

Docket No. CP11-515-000, at 29 (Feb. 29, 2012) (operation emissions).

127

See Atl. Coast Pipeline, LLC,

161 FERC ¶ 61,042 at P 305.

128

Some commenters point out that daily pipeline load factors vary significantly based on seasonal trends.

See, e.g.,

Charles River Associates 2021 Comments at 3; Williams 2021 Comments at 46.

50. Because in most instances a 100% utilization rate estimate does not accurately capture the project's climate impacts, estimated emissions that reflect a projected utilization rate will provide more useful information. The project's projected utilization rate may be calculated using, for example:

• Expected utilization data from project shippers;

• Historical usage data;

129

We note that for a greenfield pipeline project, historic data will not be available. In those cases, the project sponsor could use data from other similar projects or regional data.

• Demand projections;

• An estimate of how much capacity will be used on an interruptible basis.

51. The project sponsor is encouraged to file its projected utilization rate, as well as its justification for the rate and any supporting evidence, in its application for authorization under NGA section 3 or 7. The Commission will also consider evidence submitted by commenters and protesters in support of or opposition to the projected utilization rate.

b. Other Evidence Considered

52. Further, the Commission will consider any other evidence in the record that impacts the quantification of the project's reasonably foreseeable emissions. For example, the Commission will consider: Evidence of a net-reduction in GHG emissions where the use of transported gas displaces the use of a higher emitting alternative fuel;

130

evidence of anticipated changes in downstream usage rates over time; evidence of any real, verifiable, and measurable reduction efforts taken by the pipeline or downstream users to reduce their GHG emissions or offset their impacts;

131

and evidence that a project would displace zero-emissions electric generation. Further, other agencies, notably the EPA, have proposed regulations that may impact the emission of methane from Commission-regulated facilities.

132

If such regulations are adopted, the Commission will consider them when examining project GHG emissions. Similarly, the Commission will consider evidence from commenters and protestors supporting or challenging such estimates and assumptions.

130

For instance, in a downstream end-use analysis, Iroquois projected that its Enhancement by Compression project could result in net GHG reductions when considering the alternative fuel that may be used (

e.g.,

fuel oil for heating) by the end use customer in the event that gas is not available. Iroquois Gas Transmission, LP, Downstream GHG Report, Docket No. CP20-48-000 (filed May 19, 2020).

131

For example, the Commission may consider evidence that a downstream user purchases credits to offset its GHG emissions from the consumption of transported gas. The Commission will consider downstream user's mitigation measures according to the criteria outlined in

infra

section III.C.3 for applicant-proposed mitigation measures. With regards to construction and operational emissions, project sponsors should continue to provide evidence of measures that minimize emissions, such as using low-sulfur diesel fuel and limiting equipment idling during construction, as outlined in the Guidance Manual. Guidance Manual at 4-124. However, as described

supra

section III.A.2.a, operational emissions should now be calculated based on the project's projected utilization rate.

132

See, e.g.,

Standards of Performance for New, Reconstructed, and Modified Sources and Emissions Guidelines for Existing Sources: Oil and Natural Gas Sector Climate Review, 86 FR 63,110 (Nov. 15, 2020).

B. Level of Review and Significance

53. Under NEPA, an agency must prepare an EIS for every “major [f]ederal action[ ] significantly affecting the quality of the human environment.”

133

To determine whether an EIS is necessary for a particular action, the agency may prepare an EA,

134

described as a “concise public document” providing “sufficient evidence and analysis,” to determine whether to prepare an EIS or issue a finding of no significant impact.

135

133

42 U.S.C. 4332(C); 40 CFR 1502.3.

134

40 CFR 1501.5, 1508.1(h).

135

See

40 CFR 1501.3, 1501.5, 1501.6, 1508.1(h), (l).

54. To assess significance, the Commission determines whether the impact “would result in a substantial adverse change in the physical environment,”

136

which, as discussed, is based on considerations of the severity of adverse environmental impacts. In making that determination, the Commission uses its experience, judgment, and expertise to give record evidence appropriate weight.

137

The Commission found that “there is nothing about GHG emissions or their resulting contribution to climate change that prevents us from making that same type of significance determination.”

138

136

See Magnum Gas Storage, LLC,

137

For example, for an impact where there are no established federal standards, the Commission makes qualitative assessments to determine whether a proposed project would have a significant impact on a particular resource.

See, e.g., Tex. LNG Brownsville LLC,

169 FERC ¶ 61,130 at P 56 (“Due to the relatively undeveloped nature of the project area, the visual sensitivity of nearby recreation areas, and the lack of feasible visual screening measures, the Final EIS concluded that the project would result in a significant impact on visual resources when viewed from the adjacent Laguna Atascosa National Wildlife Refuge.”);

Alaska Gasline Dev. Corp.,

171 FERC ¶ 61,134, at PP 25, 89 (describing how the final EIS for the Alaska LNG Project found that construction and operation of the project would have significant impacts on resources such as permafrost, wetlands, forests, and caribou, but less than significant impacts on resources such as scrub and herbaceous plant communities),

order on reh'g,

172 FERC ¶ 61,214 (2020);

Transcon. Gas Pipe Line Co., LLC,

158 FERC ¶ 61,125 at P 79 (describing how the final EIS for the Atlantic Sunrise Project concluded that the project would result in adverse impacts that would be mitigated to less than significant levels).

138

N. Nat. Gas Co.,

174 FERC ¶ 61,189 at P 32.

55. Specifically, in

Northern Natural Gas Co.,

the Commission explained that:

The U.S. Court of Appeals for the District of Columbia Circuit has explained that a proposed interstate natural gas pipeline's reasonably foreseeable GHG emissions are relevant to whether the pipeline is required by the public convenience and necessity. A rigorous review of a project's reasonably foreseeable GHG emissions is also an essential part of the Commission's responsibility under NEPA to take a “hard look” at a project's environmental impacts. Determining the significance of the impacts from a proposed project's GHG emissions informs the Commission's review in a number of important respects, including its decision whether to prepare an environmental impact statement.

139

174 FERC ¶ 61,189 at P 30 (citations omitted).

56. To date, no federal agency, including the Commission, has established a threshold for determining what level of project-induced GHG emissions is significant. The Commission received a number of comments, discussed below, offering perspectives on whether and at what level it should assess the significance of a proposed project's GHG emissions.

1. Comments

57. The Commission received relevant comments in response to both the 2018 and 2021 NOIs on whether the Commission should: Determine

significance at all; set a specific significance threshold and at what level; and/or use various inventories, goals, and tools to set the threshold.

a. Whether the Commission Should Determine Significance

58. Numerous commenters (Delaware Riverkeeper, Food and Water Watch, North Carolina Department of Environmental Quality, Sabin Center, and others) argue that the Commission should make a significant impact determination based on a project's GHG emissions, which they argue would include the project's associated upstream and downstream emissions. Some commenters, for example the Sabin Center in 2018, direct the Commission to the NEPA regulation at 40 CFR 1508.27 (that was removed by amendments effective September 14, 2020), which provides that “significantly” as used in NEPA requires considerations of both the context of the action and the intensity of the impacts associated with any proposal.

140

See, e.g.,

Sabin Center 2018 Comments at 8-9.

59. In contrast, some regulated entities and other commenters express concern about the Commission determining the significance of a project's impacts on the basis of GHG emissions, especially upstream and downstream emissions. For example, INGAA and others (Energy Infrastructure Council, Williams, etc.) argue that the Commission should, at most, engage in a qualitative discussion of downstream GHG emissions because net GHG emissions are not reasonably foreseeable, and that the Commission should not assess the significance of upstream or downstream emissions.

141

Commenters such as Boardwalk state that the Commission cannot reject a project because of downstream GHG emissions or consider upstream GHG emissions, may only include a general disclosure of downstream emissions in limited circumstances (such as where all end use is known), and should generally decline to assess significance and only engage in a qualitative discussion.

142

141

See, e.g.,

INGAA 2021 Comments at 58-64. INGAA's 2021 comments update its 2018 position that the Commission should not presume that all GHG emissions are significant and should instead make a reasoned judgment whether: (1) A meaningful assessment can be made with reasonable effort based upon available information and (2) if so, whether a meaningful judgment can be formed regarding if the contribution of GHGs is likely to have a significant impact on the resource as a whole. INGAA 2018 Comments at 81-84.

142

Boardwalk 2021 Comments at 77-78, 86-90, 92-93. These comments are generally echoed by the Energy Infrastructure Council. Energy Infrastructure Council 2021 Comments at 15-16, 22-27.

60. Commenters argue that the Commission lacks the ability to make a significance determination and has no objective basis upon which to evaluate the impacts of GHG emissions associated with any specific proposed project.

143

Other commenters state that setting any significance threshold would be arbitrary

144

and potentially outside of the Commission's authority or jurisdiction.

145

143

See, e.g.,

Enbridge 2021 Comments at 103.

144

See, e.g.,

U.S. Chamber of Commerce 2021 Comments at 9.

145

See, e.g.,

API 2021 Comments at 29-32; NGSA 2021 Comments at 21-22; TC Energy 2021 Comments at 52-56; U.S. Chamber of Commerce 2021 Comments at 9.

61. Finally, commenters state that the Commission should defer to other agencies, such as CEQ or EPA, in setting a significance threshold, citing: The lack of a national energy policy or federal GHG limits; the EPA's existing authority to regulate GHG emissions under the Clean Air Act; the direction of Executive Orders 13990 and 14008, which commenters say direct EPA to examine its own GHG emissions standards; and the ongoing Interagency Work Group efforts on the SCC.

146

A few industry commenters also caution against creating uncertainty or a moving target for industry while waiting for a significance threshold to be established.

147

146

See, e.g.,

Cheniere Energy Inc. 2021 Comments at 14-16; Enbridge 2021 Comments at 104; Williams 2021 Comments at 35-38. Energy Transfer LP and the NGSA also cite CEQ's recent NEPA regulatory update and direction to agencies to propose revisions to their NEPA procedures by September 14, 2023. Energy Transfer LP 2021 Comments at 14; NGSA 2021 Comments at 19-20. The Commission's current regulations provide that the Commission will comply with CEQ's regulations except where those regulations are inconsistent with the statutory requirements of the Commission. 18 CFR 380.1. Therefore, any action taken by the Commission in a future rulemaking pursuant to CEQ's regulatory update does not prevent the Commission from issuing this policy statement.

147

See, e.g.,

BHE Pipeline Group 2021 Comments at 8-10; Cheniere Energy Inc. 2021 Comments at 17-18.

b. What the Threshold Should Be

62. Some commenters argue that the Commission should consider any net increase in GHG emissions as significant.

148

Attorneys General of Massachusetts, Connecticut, Maryland, Minnesota, New Jersey, New York, Oregon, Rhode Island, and the District of Columbia (Attorneys General of Massachusetts et al.) argues that any investment in pipeline infrastructure is inconsistent with new national emissions reductions targets and thus, project emissions can be significant on that basis alone, even if they represent a small share of national emissions, or that emissions are significant if they impede the ability of a state to meet its clean energy goals.

149

148

Ohio Environmental Council 2021 Comments at 3.

149

Attorneys General of Massachusetts et al. 2021 Comments at 6-11. The 2021 commenters are made up of a slightly different group of state attorneys general than those filing comments in 2018.

63. A few commenters suggest specific numerical thresholds. The Sabin Center recommends that the Commission assess the magnitude of GHG emissions impacts using EPA's quantification threshold of 25,000 tons per year of CO

e to identify major emitters under the Clean Air Act, social cost of GHG tools to assign a dollar value to the potential impacts of the emissions, and EPA's GHG Equivalencies Calculator as a comparison tool.

150

One commenter cites to EIS examples where the Commission stated that monetized benefits of $8 million and $28 million would be “significant” for local economies and suggests that gross climate damages between roughly $8 and $20 million should be considered significant.

151

150

Sabin Center 2018 Comments at 8-9.

151

Environmental Defense Fund, Food & Water Watch, Policy Integrity, Montana Environmental Information Center, Natural Resources Defense Council, Sierra Club, Union of Concerned Scientists, and Western Environmental Law Center (EDF) 2021 Comments at 14-15.

64. Conversely, a few commenters state that emissions from all individual projects could be considered

de minimis

and individually too small to impact climate change.

152

Others urge the Commission away from taking a bright line approach to determining significance,

153

while Driftwood Pipeline LLC urges that significance, if appropriate, requires the Commission to disclose a clear threshold.

154

152

See, e.g.,

Competitive Enterprise Institute 2021 Comments at 4, 6.

153

See, e.g.,

Enbridge 2021 Comments at 108; Russo on Energy 2021 Comments at 17-18.

154

Driftwood Pipeline LLC 2021 Comments at 3.

65. CEQ points the Commission to its 2016 guidance as an existing resource to help agencies assess GHG emissions and the effects of climate change in NEPA reviews.

155

CEQ 2021 Comments at 1.

c. Use of Inventories, Climate Goals, Programmatic Analyses, Etc. in Determining Significance

66. Some commenters recommend that the Commission use state, regional, and global GHG reduction goals to provide context and/or define

significance of GHG emissions.

156

For example, Attorneys General of Massachusetts et al. comments that the Commission already analyzes whether a proposed pipeline project is consistent with various energy and climate policies and goals and that this can be used as a metric for evaluating significance.

157

Others argue that the Commission's analysis of a proposed project's public benefits should weigh the effect of project GHG emissions on states' and the nation's abilities to comply with climate and clean energy laws and policies, such as specific energy and climate change action plans and policies.

158

The Ohio Environmental Council recommends that the Commission consider the total proposed upstream and downstream GHG emissions of all gas projects pending in any given year, giving weight to the total possible GHG emissions that could be locked in by those projects and comparing this total with international goals.

159

156

See, e.g.,

Delaware Riverkeeper Network & Berks Gas Truth 2021 Comments at 62; Ron Schaaf and Deb Evans 2021 Comments at 8; California Public Utilities Commission 2018 Comments at 11-12.

157

Attorneys General of Massachusetts et al. 2018 Comments at 17-20.

158

See, e.g.,

Attorneys General of Massachusetts et al. 2018 Comments at 17-20; Franklin Governments 2018 Comments at 2.

159

Ohio Environment Council 2018 Comments at 12-13.

67. Other commenters suggest alternative means or tools for assessing significance. For example, commenters suggest that the Commission should use a “Climate Test.”

160

Patricia Weber comments that the Commission should use such a test to determine if a project is viable in a scenario where the climate goals of the Paris agreement are met using climate and global energy market models. One commenter urges the Commission to examine acres of wetlands that will be lost due to climate impacts of proposed projects as a proxy for significance.

161

Some commenters suggest the Commission consider a programmatic or regional analysis of pipelines.

162

160

Natural Resources Defense Council (NRDC) also suggests the Commission use its forthcoming “Climate Test,” which is a tool being developed by NRDC to quantify the consistency of individual infrastructure projects with climate goals. NRDC 2021 Comments at 6. However, NRDC has not filed additional information on its “Climate Test.”

161

Healthy Gulf 2021 Comments at 14.

162

E.g.,

Attorneys General of Massachusetts et al. 2021 Comments at 8-11; EPA 2021 Comments at 1; Attorneys General of Massachusetts et al. 2018 Comments at 12-17.

68. EDF comments that a comparison of a project's emissions to international, state, or regional carbon budgets, or assessing geophysical impacts such as increases in carbon dioxide levels, global temperatures, or sea levels can be misleading and trivialize the project's impacts.

163

EDF 2021 Comments at 9-12, 16.

69. Some industry commenters state that any comparison of direct or indirect emissions should be made to global GHG inventories, not national or state inventories.

164

However, Williams states that, while the Commission should consider only direct construction and operation emissions, the Commission should compare those emissions against national GHG inventories and not against international agreements or regional targets.

165

Others oppose use of a regional analysis of GHG emissions from pipeline projects.

166

164

See, e.g.,

Boardwalk 2021 Comments at 82-83; NGSA 2021 Comments at 15. Enbridge states that comparison to these inventories would be arbitrary, but that such an approach could help contextualize the GHG emissions for the Commission and the public. Enbridge 2021 Comments at 105, 108-109.

165

Williams 2021 Comments at 38.

166

See, e.g.,

Competitive Enterprise Institute 2021 Comments at 3-4.

d. Use of the Social Cost of Greenhouse Gases

70. Several commenters generally argue for a monetization of climate damages using the Social Cost of Greenhouse Gas (SC-GHG) tools

167

to determine significance.

168

EDF recommends that the approach should be consistent with the Commission's practices for determining the significance of other monetized effects, such as economic impacts.

169

Public Interest Organizations comment that an established numerical significance threshold is not necessary, but if one is established, it should be used in tandem with the SCC tool and should not be based solely on one metric, especially not on a comparison to global emissions. Rather, they urge a holistic review of how a proposed project's impacts weigh against any benefits.

170

EDF states that if the climate damages exceeded monetized project benefits, the Commission could reject the project.

171

167

The SC-GHG collectively includes the values for the SCC, the social cost of methane (SCM), and social cost of nitrous oxide (SCN).

168

See, e.g.,

Policy Integrity Technical Conference Comments at 22-26; EPA 2021 Comments at 6; Ohio Environmental Council 2021 Comments at 2; Public Interest Organizations 2021 Comments at 43-45; Attorneys General of Massachusetts et al. 2018 Comments at 17-22; EDF 2018 Comments at 8-11. The 2018 EDF comments were filed by a slightly different set of entities than in 2021. Public Interest Organizations' 2021 comments represent 53 entities including Natural Resources Defense Council.

169

EDF 2021 Comments at 14-16.

170

Public Interest Organizations 2021 Comments at 43-45, 50-53, 60.

171

EDF 2021 Comments at 9.

71. Conversely, other commenters oppose use of the SCC tool in determining significance

172

or of using the SCC tool at all.

173

The Attorneys General of Missouri, Alabama, Alaska, Arizona, Arkansas, Georgia, Indiana, Kansas, Kentucky, Louisiana, Mississippi, Montana, Nebraska, Ohio, Oklahoma, South Carolina, South Dakota, Tennessee, Texas, Utah, and West Virginia (Attorneys General of Missouri et al.) contends that the NGA does not allow use of the SCC tool to calculate speculative damages and that its use is contrary to the Commission's public interest responsibilities. Further, they argue that NEPA does not permit the use of the SCC because NEPA does not allow agencies to rely on conclusions that are speculative or reflect substandard or outdated science.

174

172

See, e.g.,

Kinder Morgan 2021 Comments at 32-40 (stating the Commission should use the SCC tool only as a qualitative comparison tool).

173

See, e.g.,

American Forest Technical Conference Comments at 9; Competitive Enterprise Institute Technical Conference Comments at 1-2, 7-35; Enbridge 2021 Comments at 111; Energy Infrastructure Council 2021 Comments at 24-25; Williams 2021 Comments 41-43.

174

Attorneys General of Missouri et al. 2021 Comments at 2-7. A similar group, consisting of the Attorneys General of Missouri, Alabama, Alaska, Arizona, Arkansas, Georgia, Indiana, Kansas, Kentucky, Mississippi, Montana, Nebraska, Ohio, Oklahoma, South Carolina, Texas, Utah, West Virginia, and Wyoming (Attorneys General of Missouri et al.), also submitted comments in response to the Commission's technical conference,

see infra

section III.C.1, extensively critiquing potential use of the SCC. Attorneys General of Missouri et al. Technical Conference Comments at 3-15. Mr. Kirk Frost also provided comments on use of the SCC, urging the Commission to use the tool to assess GHG emissions impacts. Kirk Frost December 23, 2021 Technical Conference Comments at 4.

72. Public Interest Organizations state that, while neither the NGA nor NEPA explicitly reference the SCC tool, there is nothing in these or other federal statutes that would prohibit its use.

175

New Jersey Conservation Foundation notes that President Biden's Executive Order 13990 supports the use of the SC-GHG tools by agencies to capture the full costs of GHG emissions as accurately as possible.

176

New Jersey Conservation Foundation states that following issuance of Executive Order 13990, the Interagency Working Group on the Social Cost of Greenhouse Gases (GHG IWG) published interim SC-GHG values, which the Commission should use.

177

175

Public Interest Organizations 2021 Comments at 58.

176

New Jersey Conservation Foundation 2021 Comments at 23-24 (citing Exec. Order No. 13990, 86 FR 7037, 7040 (Jan. 25, 2021)).

177

New Jersey Conservation Foundation 2021 Comments at 24.

73. CEQ notes that it was working with representatives on the GHG IWG to develop additional guidance regarding the application of the SC-GHG tools in decision-making processes, including NEPA analysis.

178

NGSA and API urge the Commission to wait for this review to be completed.

179

NGSA further states that it would be inappropriate for the Commission to develop a likely conflicting approach for utilizing the SCC tool.

180

API states that it would violate principles of consistency for the Commission to apply the interim SC-GHG values to current proposals (

i.e.,

for the remainder of this year), knowing that these values may change and lead to different treatment for future proposals.

181

EPA states that in cases where the Commission determines that a monetary comparison between benefits and costs is appropriate, the Commission should take into account established practices for benefit-cost analyses (

e.g.,

the Office of Management and Budget's Circular A-4 and references therein). If the Commission chooses to use the SC-GHG tools, EPA states that it should disclose all assumptions and levels of uncertainty associated with the analysis.

182

178

CEQ 2021 Comments at 2.

C.f. Louisiana

Biden,

No. 21-cv-1074-JDC-KK (W.D. La.) Order Granting Preliminary Injunction (Feb. 11, 2022).

179

API 2021 Comment at 24-25; NGSA 2021 Comments at 20-21.

180

NGSA 2021 Comments at 20-21.

181

API 2021 Comment at 25, 27-28.

182

EPA 2021 Comments at 2-3.

74. The Public Interest Organizations state that monetizing impacts using the SCC tool provides the public and decisionmakers with accessible figures useful in determining whether a project is in the public interest and allows the Commission to easily compare project harms and economic benefits, whereas other metrics can misleadingly minimize climate impacts due to inadequate contextualization.

183

Public Interest Organizations 2021 Comments at 58.

75. Kinder Morgan asserts that the SCC tool relies on inputs or assumptions that introduce too much uncertainty.

184

Similarly, Attorneys General of Missouri et al. contends that the SCC tool is too speculative and arbitrary to hold up to the hard-look requirement under NEPA.

185

Rebutting this, EDF emphasizes that the GHG IWG's methodology is rigorous and based on the best available data and economic practices, such as utilizing a 300-year time horizon.

186

INGAA states that the significant variation in output among GHG IWG's interim values shows that discount rates reflect a high level of uncertainty in the models and that an agency's chosen discount rate wields an outsized influence on the end result.

187

INGAA states that the Commission should: (1) Only use the SCC tool within the NEPA evaluation, not the NGA evaluation; (2) use the SCC tool as a relative, but not absolute, measure; (3) use the SCC tool only as a threshold indicator; and (4) place any SCC estimates in the proper context.

188

184

Kinder Morgan 2021 Comments at 34-35.

185

Attorneys General of Missouri et al. 2021 Comments at 9.

186

EDF 2021 Comments at 21.

187

INGAA 2021 Comments at 67.

188

INGAA 2021 Comments at 70-73.

76. New Jersey Conservation Foundation recommends that the Commission use all of the GHG IWG's interim values provided for the SC-GHG tools (GHG IWG recommends using a discount rate of 3%, but also provides values associated with discount rates of 2.5% and 5%).

189

New Jersey Conservation Foundation 2021 Comments at 24;

see also

EDF 2021 Comments at 6-7.

77. Boardwalk and Kinder Morgan argue that the Commission should only use the SCC tool as a qualitative tool.

190

Boardwalk further asserts that there should not be any triggering levels that would result in adverse action by the Commission or a significance determination. Boardwalk contends that the use of trigger levels would create substantial regulatory uncertainty. Kinder Morgan and Williams also express concern that the SCC tool yields inherently one-sided GHG data if it is applied to a project in a manner that monetizes only the project's GHG costs and not the corresponding project benefits.

191

Energy Infrastructure Council asserts that the SCC tool is meaningless without a standard or threshold for significance and its use requires a monetized cost-benefit analysis of an entire project.

192

190

Boardwalk 2021 Comments at 103; Kinder Morgan 2021 Comments at 32-33.

191

Kinder Morgan 2021 Comments at 32-33; Williams 2021 Comments at 44-45.

192

Energy Infrastructure Council 2021 Comments at 26-27.

78. Kinder Morgan states that the SCC tool was not designed for project-specific analysis but could be used as a screening tool in a qualitative analysis. If the Commission uses the SCC tool, Kinder Morgan recommends that it should explain why and how it was used.

193

This explanation should include information about the SCC's function, its mechanism, its embedded limitations and assumptions, and the specific reason for its application in a given circumstance. Kinder Morgan states that this type of explanation is vital to avoid misleading the public about the purpose of the SCC calculation and the meaning of its results.

194

Spectra Energy Partners, LP and Seneca Resources Corporation contend that the Commission has no basis to designate a particular SCC dollar amount as significant, and any such designation would be arbitrary and could not meaningfully inform the Commission's decision making or the public.

195

Additionally, Kinder Morgan states that the Commission should not use the SCC tool to determine mitigation measures or conditions because no statute requires that the Commission implement mitigation based on calculations from such a tool.

196

193

Kinder Morgan 2021 Comments at 42.

194

Id.

195

Seneca Resources Corp. 2018 Comments at 9; Spectra Energy Partners, LP 2018 Comments at 87.

196

Kinder Morgan 2021 Comments at 42.

2. Appropriate Level of NEPA Review and Significance Determination

79. To determine the appropriate level of NEPA review, the Commission is establishing a significance threshold of 100,000 metric tons or more per year of CO

e. In calculating this emissions estimate, Commission staff will apply the 100% utilization or “full burn” rate for natural gas supplies delivered by the proposed project and will prepare an EIS if the estimated emissions from the proposed project may exceed the 100,000 metric tons per year threshold.

80. An emissions threshold of 100,000 metric tons per year of CO

e captures the majority of annual emissions generated by Commission authorized projects, including those that may result in incremental GHG emissions over a long duration that may have a significant effect upon the human environment. Establishing a threshold for NEPA purposes also provides Commission staff, industry, and other stakeholders clarity regarding whether a particular project will result in the preparation of either an EA or an EIS. We believe that such clarity ultimately benefits both the regulated community and public by ensuring certainty regarding the Commission's process for reviewing applications for natural gas infrastructure.

81. In its NEPA document, staff will estimate the proposed project's GHG emissions based on all relevant evidence submitted in the record—including the project's utilization rate, offsets, and mitigation. A project with estimated emissions of 100,000 metric tons per year of CO

e or greater will be presumed to have a significant effect, unless record evidence refutes that

presumption.

197

While the 100,000 metric ton presumption will serve as a guidepost, facilitating transparent, predictable analysis of a proposed project's contribution to climate change, our analysis will continue to consider all evidence in the record on a case-by-case basis. As part of that analysis, the Commission will continue to consider any emerging tools as well as any forthcoming frameworks or analysis issued by CEQ or other agencies on this issue. Finally, as noted at the outset, we encourage commenters to address this approach to assessing significance—including the 100,000 metric ton CO

e threshold.

197

When examining a project's GHG emissions, the Commission will consider record evidence of the construction, operational, and, where determined to be reasonably foreseeable, downstream and upstream GHG emissions that reoccur annually over the life of the project.

a. Commission Authority To Establish a Threshold

82. Section 3 of the NGA requires the Commission to approve an application for the exportation or importation of natural gas unless the proposal “will not be consistent with the public interest.”

198

Similarly, under section 7, the Commission must find a proposed project is or will be required by the present or future public convenience and necessity.

199

The Commission has long regarded section 3's “public interest” standard and section 7's “public convenience and necessity” standard as substantially equivalent.

200

In considering applications under section 3 or section 7, the Commission must “evaluate all factors bearing on the public interest.”

201

The Commission has recognized from its earliest decisions that it may consider the end use of gas as a factor in assessing the public interest

202

and has long considered the impact of natural gas combustion on air pollution.

203

198

15 U.S.C. 717b(a).

199

Id.

717f(c), (e).

200

Distrigas Corp.

FPC,

495 F.2d 1057, 1065 (D.C. Cir.).

201

Atl. Ref. Co.

Pub. Serv. Comm'n of State of N.Y.,

360 U.S. 378, 391 (1959).

202

See, e.g., Hope Nat. Gas Co.,

4 FPC 59, 59, 66-67 (1944) (stating that “considerations of conservation are material to the issuance of certificates of public convenience and necessity under section 7” and authorizing a project in large part because of the particular end use of the gas);

see N. Nat. Gas Co.,

15 FPC 1634, 1641 (1956) (Connole, Comm'r, dissenting) (contending that the Commission has “long held that considerations of conservation, inferior and superior uses, and related matters are relevant to determining whether the public convenience and necessity require the issuance of a certificate”).

203

Transwestern Pipeline Co.,

36 FPC 176, 185-186, 189-191 (1966) (citing

FPC

Transcon. Gas Pipe Line Corp.,

365 U.S. 1 (1961) (

Transco

), for the proposition that the “end use of gas was properly of concern to [the Commission], and made it clear that air pollution was a relevant consideration”).

Cf. Am. La. Pipe Line Co.,

16 FPC 897, 899-900 (1956) (“[T]here is a public need for and will be a public benefit from [the proposed] natural-gas service . . . . This need and benefit arise from the facts, among others, . . . that natural gas is a clean, convenient and efficient fuel.”).

83. As discussed above, the courts have interpreted the Commission's obligations under NEPA to require analysis of downstream GHG emissions for NGA section 7 certificate projects, but do not require an analysis of either downstream or upstream GHG emissions for section 3 export projects.

204

As also discussed above, the Commission has previously acknowledged that upstream emissions for NGA section 7 certificate projects may be difficult to quantify. However, as noted, the Commission will continue to consider on a case-by-case basis whether GHG emissions from upstream production activities are a reasonably foreseeable and causally connected result of a proposed project.

205

204

See supra

PP 34-37.

205

See supra

P 42.

84. Contrary to the suggestion of some commenters, the Commission would not intrude into another agency's domain by establishing a significance threshold. The Commission does not propose to set an emissions standard that projects will be expected to meet; rather, the threshold would be an indication of potential significance for purposes of the Commission's review of a project's environmental impacts under NEPA and trigger the preparation of an EIS.

206

The Commission notes that CEQ and EPA are undertaking initiatives that may culminate in the establishment of a significance threshold for GHG emissions or that may further impact the Commission's determination of GHG significance in its NEPA analysis. If CEQ or EPA issues any future guidance regarding the evaluation of GHG emissions, the Commission may adjust its methods for determining the significance of GHG emissions consistent with that guidance.

85. As discussed above, NEPA requires the Commission to take a “hard look” at the environmental consequences of a proposed action and to prepare an EIS disclosing its analysis to the public where its action may significantly affect the quality of the human environment, or to prepare an EA for a proposed action that is not likely to have significant effects or when the significance is unknown to determine if an EIS is necessary. We note that neither EPA nor CEQ raise objections to the Commission determining the significance of GHG emissions; in fact, EPA points to Executive Order 14008, which directs the federal government to prioritize assessment, disclosure, and mitigation of climate pollution and climate-related risks, in response to the Commission's query on how it could determine the significance of a project's GHG emissions.

207

EPA 2021 Comments at 6.

86. As discussed above, NEPA requires the Commission to determine whether a project would have any significant effects on the environment, including the effects of GHG emissions on the climate.

208

Moreover, courts have rejected the claim that under the NEPA framework, the determination of whether an impact is significant must not involve any subjective judgment calls.

209

208

See supra

PP 23-25.

209

Spiller

White,

352 F.3d at 244 n.5.

87. We are establishing a uniform GHG emissions threshold because GHG emissions affect climate to the same degree, regardless of the location or specifics of a particular project. Establishing such a threshold will provide the Commission a workable and consistent path forward to analyze proposed projects. Further, a numerical threshold is a clear, consistent standard that can be easily understood and applied by the regulated community and interested stakeholders.

b. Rationale for an Emissions Threshold of 100,000 Metric Tons per Year

88. Human impact on the warming of the global climate system is unequivocal.

210

Even if deep reductions in GHG emissions are achieved, the planet is projected to warm by at least 1.5 degrees Celsius (°C) by 2050.

211

This level of warming will present major global consequences. For example, extreme temperature events that may have occurred once in 10 years on average in a climate without human influence will occur 4.1 times as frequently and be 1.9 °C hotter.

212

Agricultural and ecological drought events that may have occurred once in 10 years on average across drying regions in a climate without human influence will occur twice as frequently.

213

Warming beyond 1.5 °C presents even more severe consequences. The Intergovernmental Panel on Climate Change states that “[w]ith every additional increment of global warming, changes in extremes continue to become larger.”

214

For example, every subsequent 0.5 °C of warming “causes clearly discernible increases in the intensity and frequency of hot extremes, including heatwaves (

very likely

), and heavy precipitation

(

high confidence

), as well as agricultural and ecological droughts in some regions (

high confidence

).”

215

Because of the dire effects at stake, even relatively minor GHG emissions pose a significant threat, 100,000 metric tons per year of project GHG emissions will capture all natural gas projects that have what we believe to be the potential for causing significant impacts on climate, given the typical lifespans of authorized projects. For a single natural gas project with a lifespan of 30 years, this threshold represents a total of three million metric tons of GHG emissions.

210

IPCC Report at SPM-5.

211

See

IPCC Report at SPM-17.

212

IPCC Report at SPM-23.

213

IPCC Report at SPM-23.

214

IPCC Report at SPM-19.

215

IPCC Report at SPM-19 (emphasis in original).

89. Based on an internal review of natural gas projects from 2008 to 2021, a 100,000 metric tons per year threshold will cover the vast majority of potential GHG emissions from natural gas projects authorized by the Commission. For context, projects that likely have 100,000 metric tons per year or more of GHG emissions include projects transporting an average of 5,200 dekatherms per day and projects involving the operation of one or more compressor stations or LNG facilities.

90. Outside the NEPA context, other federal and state agencies that have established thresholds to evaluate or regulate GHG emissions from an analysis of the emissions from regulated sources. Most notably, in 2012, EPA issued the Tailoring Rule to regulate GHG emissions from stationary sources of air pollution under the Prevention of Significant Deterioration (PSD)

216

and Title V

217

permitting programs

218

and proposed to phase in the regulation of GHG emissions in two steps. Under Step 1, sources already subject to the PSD permitting program for at least one non-GHG pollutant (“anyway” sources) were required to utilize best available control technology (BACT) for GHG emissions

219

if they increased net GHG emissions by at least 75,000 tons per year of CO

216

The PSD permitting program is part of the New Source Review program, which requires new stationary sources and major modifications to existing major sources to obtain preconstruction permits. PSD is designed to prevent air quality deterioration in regions that are attaining the National Ambient Air Quality Standards by requiring major sources or major modifications to install the Best Available Control Technology (BACT). Major sources under the PSD program are defined as facilities that emit or have the potential to emit 250 tons per year of any criteria air pollutant or 100 tons per year of any criteria air pollutant for specific types of facilities listed in the statute. 42 U.S.C. 7479(1). The six criteria pollutants are carbon monoxide, ground-level ozone, lead, nitrogen dioxide, particulate matter, and sulfur dioxide. 40 CFR pt. 50.

217

The Title V program requires major stationary sources to obtain a single operating permit that consolidates all of the permitting requirements in the Clean Air Act into a single permit, including PSD, New Source Performance Standards, and National Emission Standards for Hazardous Air Pollutants. Major sources under the Title V program are defined as any stationary facility that emits or has the potential to emit 100 tons per year of any hazardous air pollutant, except GHGs. 42 U.S.C. 7602(j). The Clean Air Act Amendments of 1990 originally designated over 180 chemicals as hazardous air pollutants, and EPA has the authority to modify the list through rulemaking. 42 U.S.C. 7412(b)-(c).

218

Prevention of Significant Deterioration and the Title V Greenhouse Gas Tailoring Rule, 75 FR 31514 (June 3, 2010) (Tailoring Rule).

219

BACT is used to minimize emissions based on the maximum degree of control that the facility can achieve as determined by the permitting authority on a case-by-case basis. BACT may be a design, equipment, work practice, or operational standard, such as add-on control equipment, fuel cleaning or treatment, or innovative fuel combustion techniques. Note that BACT for minimizing GHG emissions at natural gas facilities is limited.

91. Under Step 2, EPA expanded the Tailoring Rule by requiring a new source or a major modification to an existing source to obtain PSD and/or Title V permits based on GHG emissions alone. Sources that had the potential to emit at least 100,000 tons per year of CO

e would become newly subject to the PSD and/or Title V requirements, even if they did not exceed the statutory threshold for any other pollutant. Additionally, modifications to an existing source already subject to PSD and/or Title V that increased net GHG emissions by at least 75,000 tons per year of CO

e would be subject to PSD requirements regardless of whether there was an increase in the emissions of any other pollutant.

220

EPA also planned a Step 3 to further reduce the threshold, although not below 50,000 tons per year of CO

e. The Supreme Court struck down relevant portions of the Tailoring Rule before EPA finalized Step 3.

92. In setting the 75,000 tons and 100,000 tons per year of GHGs thresholds, EPA considered the administrative burden of permitting the estimated number of additional facilities under each threshold and the percentage of total national stationary source GHG emissions that would be covered under the threshold.

221

For example, under Step 1, EPA estimated a 5% increase in the total annual cost to run the permitting programs and that approximately 65% of GHG emissions would be covered. Under Step 2, EPA estimated that approximately 550 new sources would become subject to the PSD and Title V programs, increasing total annual costs to run the programs by 42% and covering 67% of GHG emissions. EPA further found that lowering the threshold to 50,000 or 25,000 tons per year of CO

e would drastically increase both the number of new facilities requiring permits and the cost of administering the programs but would only marginally increase the percentage of GHG emissions covered to 70% and 75%, respectively.

221

Tailoring Rule, 75 FR at 31533-80.

93. In 2014, the Supreme Court invalidated portions of the Tailoring Rule, holding that EPA may not use GHG emissions as the sole basis for determining whether a source is subject to a PSD or Title V permitting requirements.

222

While the Supreme Court's ruling struck down Step 2 of the Tailoring Rule, it upheld Step 1 and allowed EPA to continue to regulate GHG emissions from “anyway” sources. Notably, the decision did not discuss EPA's methodology for establishing the thresholds; it only ruled that deviating from the 100 and 250 tons per year statutory thresholds in the Clean Air Act when requiring sources to newly obtain PSD or Title V permits based solely on GHG emissions under Step 2 was impermissible.

222

Util. Air Regul. Grp.

EPA,

573 U.S. 302, 320 (2014).

94. Further, at least two agencies in California that are directed to determine the significance of GHG emissions and climate impacts of proposed projects under the California Environmental Quality Act have also proposed or established thresholds of significance based on an analysis of regulated sources. First, in 2008, the California Air Resources Board (California ARB) proposed finding a less than significant impact for a proposed industrial project that, with mitigation, emits no more than 7,000 metric tons per year of CO

e from non-transportation sources, including combustion and fugitive emissions.

223

Second, the South Coast Air Quality Management District (South Coast AQMD) adopted an interim GHG significance threshold of 10,000 metric tons of CO

e per year for stationary

sources of air pollution in 2008.

224

Both California ARB and South Coast AQMD found that their thresholds would capture approximately 90% of emissions from their respective regulated sources.

225

223

California ARB, Preliminary Draft Staff Proposal, Recommended Approaches for Setting Interim Thresholds for Greenhouse Gases under the California Environmental Quality Act (Oct. 24, 2008) (CEQA Proposed Interim Thresholds). In addition, California ARB proposed to require these projects to meet performance standards for construction-related emissions and transportation to support a finding of less than significant impacts. CEQA Proposed Interim Thresholds at attach. A.

224

South Coast AQMD, Interim CEQA GHG Significance Threshold for Stationary Sources, Rules and Plans (Dec. 5, 2008),

http://www.aqmd.gov/docs/default-source/ceqa/handbook/greenhouse-gases-(ghg)-ceqa-significance-thresholds/ghgboardsynopsis.pdf?sfvrsn=2.

225

Id.

at 4; CEQA Proposed Interim Thresholds at attach. A.

95. Like EPA and the California agencies, we are basing our threshold on an analysis of regulated sources. Although we are adopting a conceptually similar methodology in establishing our threshold, we note that our approach will cover a larger number of emissions than the threshold established by EPA in the Tailoring Rule. EPA's thresholds of 75,000 and 100,000 tons per year accounted for only 65% and 67% of emissions from EPA-regulated sources, respectively, whereas our proposed threshold of 100,000 metric tons per year would deem nearly three-quarters of Commission-regulated natural gas project, which collectively account for roughly 99% of GHG emissions from Commission-regulated natural gas projects, to have a significant impact on climate change.

3. Other Metrics

96. As noted above, commenters argue for and against the use of various existing GHG inventories or goals as a comparison tool to determine significance. Comparison to an existing GHG inventory or goal presents substantially different percentages based on the chosen goal (international, state, regional, or local). Because different projects may have different potential purposes and the purpose of a project may be characterized to support or oppose a particular viewpoint, we do not believe that tying the Commission's significance determination for a proposed project's GHG emissions to a particular inventory or goal is appropriate. However, we recognize that this type of comparison can be helpful to inform the Commission's analysis and the public, especially when presented using a consistent metric across proposed projects under consideration by the Commission. We note that many commenters reference the SC-GHG as one tool. To the extent permitted by law,

226

the Commission could consider the SC-GHG in the future.

226

Currently, two pending court cases challenge use of the IWG's interim values by federal agencies.

Mo.

Biden,

—— F. Supp. 3d ——, 2021 WL 3885590 (E.D. Mo. Aug. 31, 2021), appeal filed, No. 21-3013 (8th Cir.);

La.

Biden,

No. 21-cv-1074-JDC-KK (W.D. La).

C. Mitigation

97. Federal agencies can use mitigation to minimize the potential adverse environmental effects of their actions,

227

and mitigation is used by the Commission in reviewing NGA sections 3 and 7 proposals.

228

227

Mitigation is measures that avoid, minimize, or counterbalance effects caused by a proposed action by: (1) Avoiding the impact altogether by not taking a certain action or parts of an action; (2) minimizing impacts by limiting the degree or magnitude of the action and its implementation; (3) rectifying the impact by repairing, rehabilitating, or restoring the affected environment; (4) reducing or eliminating the impact over time by preservation and maintenance operations during the life of the action; and/or (5) compensating for the impact by replacing or providing substitute resources or environments. 40 CFR 1508.1.

228

As discussed

supra

P 26, NEPA contains no substantive requirement that environmental impacts be mitigated or avoided, however, the environmental document must include a mitigation discussion that provides “sufficient detail” to indicate that environmental impacts have been fairly evaluated.

S. Fork Band Couns. of W. Shoshone of Nev.

U.S. Dep't of Interior,

588 F.3d 718, 727 (9th Cir. 2009);

see also Nat'l Parks & Conservation Ass'n

U.S. Dep't of Transp.,

222 F.3d 677, 681 n.5 (9th Cir. 2000) (stating that mitigation measures proposed in an EIS “need not be legally enforceable, funded, or even in final form to comply with NEPA's procedural requirements”).

98. The NGA grants the Commission broad authority to attach reasonable terms and conditions to NGA section 7 certificates of public convenience and necessity and NGA section 3 authorizations.

229

The Commission has consistently exercised this authority to attach environmental conditions that mitigate the adverse environmental impacts of a proposed project, and the Commission is not precluded from utilizing this authority to require a project sponsor to mitigate all, or a portion of, the impacts related to a proposed project's GHG emissions. Therefore, consistent with the discussion provided herein, going forward project proponents are encouraged to propose mitigation that will minimize climate impacts. The Commission will consider any mitigation measures proposed by the project sponsor on a case-by-case basis when balancing the need for a project against its adverse environmental impacts and may require additional mitigation as a condition of an NGA section 3 authorization or section 7 certificate.

229

See supra

P 22;

see also

15 U.S.C. 717b(e)(3)(A) (providing the authority to approve an application for an LNG Terminal, “in whole or part, with such modifications and upon such terms and conditions as the Commission find[s] necessary or appropriate”).

1. Technical Conference on GHG Mitigation

99. On November 19, 2021, the Commission held a Commission staff-led technical conference to discuss methods project sponsors may use to mitigate the effects of direct and indirect greenhouse gas emissions resulting from Natural Gas Act sections 3 and 7 authorizations.

230

Representatives from industry, academia, non-governmental organizations, and state regulatory commissions participated as panelists, with discussion topics including: How the Commission could determine the quantity of reasonably foreseeable GHG emissions resulting from a project proposed under section 3 or 7 of the NGA and the appropriate level of mitigation for such emissions; types of mitigation measures a project sponsor could employ to reduce the amount of GHG emissions associated with a proposed project; and methods for the continued verification and accounting of GHG mitigation during project operation, as well as cost impacts to the industry from implementing GHG mitigation measures and how project sponsors might recover those costs.

230

See

Transcript of Greenhouse Gas Mitigation: Natural Gas Act Sections 3 and 7 Authorizations, Docket No. PL21-3-000 (issued Dec. 22, 2021) (Technical Conference Transcript).

100. In addition to the panelists' written statements, the Commission received over 20 comments in response to the technical conference. The Commission considered these statements and comments in developing the mitigation policy described below.

2. Authority To Require Mitigation

101. Some commenters state that the Commission has broad authority under the NGA to place conditions in certificate authorizations requiring pipeline companies to mitigate GHG impacts,

231

while others argue that the Commission does not have authority under the NGA or NEPA to impose mitigation measures,

232

especially

measures to mitigate upstream or downstream GHG emissions.

233

Specifically, commenters argue that the Commission's authority under NGA section 7(e) to place conditions on a certificate is limited by the statutory purpose to regulate interstate transportation to ensure reliable access to plentiful natural gas at reasonable prices.

234

Commenters further assert that the Commission has no authority to establish environmental policy and that the Commission cannot use its conditioning authority to indirectly mitigate an effect that it has no authority to directly mitigate.

235

231

See, e.g.,

Policy Integrity Technical Conference Comments at 2; Policy Integrity 2021 Comments at 14-15, 21; Public Interest Organizations 2021 Comments at 71-72;

see also

American Forest Technical Conference Comments at 4-5, 7-10 (stating that to the extent the courts have clarified the Commission's duty to consider GHG emissions and require mitigation for such impacts, that it supports the Commission considering mitigation on a case-by-case basis to avoid the uncertainty posed by the threat of litigation and the possibility of a court vacating the project's certificate).

232

See, e.g.,

Boardwalk Technical Conference Comments at 7; Dr. Jason Scott Johnston Technical Conference Comments at 1; TC Energy Technical Conference Comments at 4; API 2021 Comments at

29-30;

see also

Williams Technical Conference Comments at 17 (claiming that there is no reasonable basis for the Commission to require project sponsors to submit mitigation proposals with their applications because the technical conference demonstrated a lack of evidentiary support for any specific mitigation methods, offered no specific proposals regarding the levels of fees, offsets, or caps, and proposed no concrete and cost-effective means to mitigate emissions).

233

API Technical Conference Comments at 5; Boardwalk Technical Conference Comments at 10; Consolidated Edison Company of New York, Inc. and Orange and Rockland Utilities, Inc. (collectively, Con Edison) Technical Conference Comments at 5; Hon. Joseph T. Kelliher Technical Conference Comments at 1; INGAA Technical Conference Comments at 6-7; TC Energy Technical Conference Comments at 8; API 2021 Comments at 31; INGAA 2021 Comments at 74-83; TC Energy 2021 Comments at 56-58.

234

See, e.g.,

Hon. Joseph T. Kelliher Technical Conference Comments at 1 (citing

NAACP

FPC,

425 U.S. 662, 669-70 (1976));

id.

at 8-9 (asserting that the proper place to consider GHG emissions (direct only) is under the Commission's balancing test, where a project sponsor may choose to voluntarily offset emissions); TC Energy Technical Conference Comments at 8; INGAA 2021 Comments at 74-76.

235

See, e.g.,

Boardwalk Technical Conference Comments at 11-13 (arguing that

Transco

does not authorize the Commission to indirectly regulate upstream and downstream emissions); Enbridge Technical Conference Comments at 5, 16, 21; Hon. Joseph T. Kelliher Technical Conference Comments at 4; INGAA 2021 Comments at 76-77.

102. Commenters also claim that any attempt to mitigate indirect GHG emissions would infringe on the regulatory authority of other federal and state agencies and result in back-door regulation of energy policy.

236

Specifically, commenters state that any attempt by the Commission to mitigate upstream or downstream GHG emissions would interfere with state resource decisions and usurp issues of national energy and environmental policy that Congress vested in other federal authorities.

237

For example, commenters argue that Congress has delegated authority to the EPA and state agencies to regulate GHGs under the CAA.

238

Even if the Commission had the authority to impose mitigation measures for upstream or downstream GHG emissions, commenters argue that the Commission must first establish that those GHG emissions are reasonably foreseeable and have a sufficiently close causal connection (akin to proximate causation under tort law)

239

to the authorization of a project under NEPA, and if not, should not be considered for mitigation purposes.

240

Lastly, commenters question reliance on

Sabal Trail

to support the Commission's authority to impose mitigation.

241

236

See, e.g.,

API Technical Conference Comments at 2, 4; Edison Electric Institute (EEI) Technical Conference Comments at 9-10; Enbridge Technical Conference Comments at 18-19, 23-24; Hon. Joseph T. Kelliher Technical Conference Comments at 5; Attorneys General of Missouri et al. Technical Conference Comments at 3 (citing

S. Coast Air Quality Mgmt. Dist.

FERC,

621 F.3d 1085, 1092 (9th Cir, 2010)); TC Energy Technical Conference Comments at 6-7; Boardwalk 2021 Comments at 10. Commenters further argue that the NGA was not enacted to comprehensively regulate the natural gas industry, but instead to fill a regulatory gap over interstate gas transportation and sales; therefore, Congress left the regulation of upstream production and downstream consumption to the states. Enbridge Technical Conference Comments at 16-17; Hon. Joseph T. Kelliher Technical Conference Comments at 2 (citing

NAACP

FPC,

425 U.S. at 669-70;

State of Cal.

Southland Royalty Co.,

436 U.S. 519, 523 (1989);

ONEOK, Inc.

Learjet, Inc.,

575 U.S. 373, 378, 384-85 (2015);

ANR Pipeline Co.

FERC,

876 F.2d 124, 132-33 (D.C. Cir. 1989)).

237

INGAA Technical Conference Comments at 8; Boardwalk 2021 Comments at 107; Con Edison Technical Conference Comments at 6-7 (stating that the state regulators are the best positioned to determine and impose mitigation measures for upstream and downstream GHG emissions); INGAA 2021 Comments at 77-79.

238

American Public Gas Association (APGA) Technical Conference Comments at 5-6; EEI Technical Conference Comments at 9-10; Enbridge Technical Conference Comments at 23-24; TC Energy Technical Conference Comments at 9-10.

239

Specifically, commenters argue that the Commission should rely on

Center for Biological Diversity,

which states that “the legal analysis in

Sabal Trail

is questionable at best” and that “[i]t fails to take seriously the rule of reason announced in

Public Citizen

or to account for the untenable consequences of its decision.”

Center for Biological Diversity,

941 F.3d at 1300;

see also

AGA Technical Conference Comments at 13-14; Boardwalk Technical Conference Comments at 16-17; Hon. Joseph T. Kelliher Technical Conference Comments at 3; INGAA Technical Conference Comments at 12-13; TC Energy Technical Conference Comments at 13-14.

240

API Technical Conference Comments at 4; EEI Technical Conference Comments at 6; INGAA Technical Conference Comments at 14; Williams Technical Conference Comments at 5.

241

See

AGA Technical Conference Comments at 12-13 (arguing that the Commission should not rely on this statement of dicta because the issue of mandatory mitigation was not at issue in this case; rather, the court only addressed whether the Commission is, in some circumstances, required by NEPA to include a discussion of downstream GHG emissions when conducting its environmental review); Boardwalk Technical Conference Comments at 16 (same); Enbridge Technical Conference Comments at 20 (same); Hon. Joseph T. Kelliher Technical Conference Comments at 3-4 (same); TC Energy Technical Conference Comments at 12 (same).

103. We disagree with contentions that the Commission does not have the authority under the NGA or NEPA to require mitigation of GHG emissions by a project sponsor. The D.C. Circuit stated in

Sabal Trail,

that “the [Commission] has legal authority to mitigate” greenhouse-gas emissions that are an indirect effect of authorizing a pipeline project.

242

And, as early as 1961, the Supreme Court recognized that the Commission's predecessor, the Federal Power Commission, had the authority to consider downstream uses, and specifically, the impact of end-users combusting transported gas on air quality, as part of its public convenience and necessity determination under the NGA.

243

Both NGA sections 3 and 7 authorize the Commission to attach “such reasonable terms and conditions as the public convenience and necessity may require.”

244

Pursuant to this authority, the Commission has conditioned NGA section 7 certificates and section 3 authorizations on mitigation of impacts of the proposed project.

245

Moreover, courts have interpreted this provision broadly and given the Commission latitude in deciding what types of mitigation to require.

246

242

Sabal Trail,

867 F.3d at 1374.

243

Transco,

365 U.S. at 17;

see also

Enbridge Technical Conference Comments at 12-13, 35-38 (recommending the Commission await direction from Congress in choosing a mitigation level, especially if requiring project sponsors to mitigate to less than significant levels and noting that mitigation to zero is not practicable if downstream or upstream emissions are included).

107. The Commission will consider the project's impact on climate change, including the project sponsor's mitigation proposal, as part of its public interest determination under NGA section 3 or 7.

261

When making the public interest determination, the Commission will assess the adequacy of the project sponsor's proposed mitigation on a case-by-case basis and will consider the project's impact on climate change as one of many factors.

262

Further, the Commission may require additional mitigation of a project's direct GHG emissions as a condition of the authorization, should the Commission deem a project sponsor's proposed mitigation inadequate to support the public interest determination.

261

Attorneys General of Massachusetts et al. urges the Commission to consider the impacts of any mitigation measures on environmental justice communities. Attorneys General of Massachusetts et al. Technical Conference Comments at 5-6.

262

Jennifer Danis, Senior Fellow with the Sabin Center for Climate Change Law and a panelist at the GHG Technical Conference on Panel 1, recommends that the Commission should not consider the effect of any mitigation measures in its public interest determination but should only consider mitigation measures once the Commission has determined that public convenience and necessity absolutely requires the project. Jennifer Danis Technical Conference Statement at 8-11. As explained in the Certificate Policy Statement, the Commission considers all factors, including the extent to which adverse impacts are mitigated, to determine whether a project is in the public convenience and necessity.

Certification of New Interstate Natural Gas Pipeline Facilities,

178 FERC ¶ 61,107 at PP 70, 93-95.

108. Also we note that NEPA does not preclude the Commission from approving a project with significant adverse impacts.

263

If a project's emissions equal or exceed the 100,000

metric tons per year significance threshold and the project sponsor's proposed mitigation will reduce the project's GHG emissions below that threshold, the Commission will consider that mitigation in determining whether it can make a finding of no significant impact.

263

See supra

section II.B.

109. While the Commission has broad authority to require mitigation of GHG emissions by a project sponsor, we are not mandating here any particular form of mitigation.

264

A project sponsor is free to propose any mechanism to mitigate the project's GHG emissions.

265

However, in order to ensure that any GHG emissions reduction mechanisms achieve real, verifiable, and measurable reductions, any proposed mechanisms should:

264

Commenters emphasize the need for flexibility in assessing mitigation measures.

See, e.g.,

Enbridge Pre-Conference Comments at 9; Enbridge Technical Conference Comments at 46-47 (suggesting that, depending on a variety of factors, the applicant may or may not be able to propose appropriate mitigation at the time of the project application); Hon. Joseph T. Kelliher Technical Conference Comments at 11 (recommending alternatives to imposing mitigation requirements such as revising the Commission's 2015 Modernization Policy Statement, issuing a new GHG policy statement that either allows limited section 4 rate filings to recover costs or clarifies the level of shipper support required to support establishment of a tracker surcharge and recommending that such a policy address lost and unaccounted-for fuel, or implementing a fast track certificate process for project sponsors that voluntarily commit to mitigate direct GHG emissions); INGAA Technical Conference Comments at 30; Magnolia LNG LLC Technical Conference Comments at 2; TC Energy Technical Conference Comments at 5, 21 (arguing against the Commission requiring marked-based mitigation measures). A few commenters either oppose use of the SCC in determining a required level of mitigation for project emissions, Enbridge Technical Conference Comments at 6, 38-39, or urge the Commission to use the SCC to monetize the impacts of any GHGs that are not able to be mitigated, Attorneys General of Massachusetts et al. Technical Conference Comments at 7. As described above, the Commission does not propose to mandate any particular level or type of mitigation.

265

For example, Mountain Valley Pipeline, LLC, proposed to offset the operational emissions of the Mountain Valley Pipeline Project by purchasing carbon offset credits equivalent to 90% of GHG emissions associated with the project's operations in its first 10 years of service from a new methane abatement project located at a mine in southwest Virginia. Mountain Valley Pipeline, LLC, Carbon Offset Commitment for Mountain Valley Pipeline Project Operations, Docket No. CP21-57-000 (filed July 12, 2021).

a. Be both real and additional—the emissions reductions would not have otherwise happened unless the proposed reduction mechanism was implemented, and the associated reductions occur beyond regulatory requirements;

266

Regulatory requirements include those imposed by the Commission and other federal and state regulatory agencies. However, project sponsors may include participation in voluntary regulatory programs that reduce GHG emissions.

b. be quantifiable—any emissions reductions must be calculated using a transparent and replicable methodology;

c. be unencumbered—seller has clear ownership of or exclusive rights to the benefits of the GHG reduction; and

d. be trackable—the project sponsor must also propose means for the Commission to monitor and track compliance with the proposed mitigation measures for the life of the project.

110. Commenters express concerns with how the Commission will determine whether mitigation measures are verifiable or how the Commission will monitor or track compliance with mitigation measures in a way that avoids double counting emissions reductions.

267

Commenters point out that other federal agencies and states are already monitoring GHG emissions from certificated projects, such as EPA's GHG Reporting Rule, so a Commission-designed monitoring scheme would be duplicative and unnecessary.

268

EEI recommends that the Commission explore interagency agreements or memorandums of understanding (MOU) with agencies like EPA and PHMSA to avoid redundancies and clarify mitigation responsibilities,

269

while INGAA states that such agreements or MOUs would be insufficient.

270

267

See, e.g.,

INGAA Technical Conference Comments at 38-39. Dr. Carl Pechman, Director of the National Regulatory Research Institute and a panelist at the GHG Technical Conference on Panel 3, provides extensive comments on how the Commission could establish accounting protocols and offset tracking. Dr. Carl Pechman Technical Conference Statement at 1-15.

268

APGA Technical Conference Comments at 8-9; Enbridge Technical Conference Comments at 48-49; INGAA Technical Conference Comments at 40-41; TC Energy Technical Conference Comments at 5-6, 22-23. Similarly, commenters state that the Commission should defer to other agencies, such as the EPA and state environmental agencies, that are already taking regulatory action regarding emissions, express concern over the potential for inconsistent mitigation requirements between agencies, and/or point to EPA's methane regulation proposal to reduce GHG emissions from new, reconstructed, modified, and existing facilities in the oil and gas source category under section 111 of the Clean Air Act. APGA Technical Conference Comments at 5; EEI Technical Conference Comments at 10-11; INGAA Technical Conference Comments at 30-32; NGSA Technical Conference Comments at 6-7. Conversely, one commenter encourages the Commission to use resources from the EPA's pending rulemaking. Attorneys General of Massachusetts et al. Technical Conference Comments at 6-7 (referencing Standards of Performance for New, Reconstructed, and Modified Sources and Emissions Guidelines for Existing Sources: Oil and Natural Gas Sector Climate Review, 86 FR 63110 (Nov. 15, 2021)).

269

EEI Technical Conference Comments at 12-14.

270

INGAA Technical Conference Comments at 40-41.

111. We believe it best not to mandate mitigation based on a specific volume or proportion of emissions. Encouraging project sponsors to submit proposed mitigation measures as opposed to mandating a certain level of mitigation for all projects allows the Commission to consider a project sponsor's proposed mitigation plan in comparison to the project's benefits, such as fuel switching or providing reliable gas service, when making a public interest determination and allows project sponsors the flexibility to choose what mitigation measures work best for their individual project. Moreover, we recognize that determining an appropriate amount of mitigation, particularly for downstream uses, depends on a variety of complex factors, some of which may not be known at the time of an application, such as state and local climate change policies, the interconnected nature of the natural gas pipeline system, long-term changes in natural gas supply sources, changes in demand for natural gas over time, individual companies' long-term goals to reduce GHG emissions, the availability of renewable energy credits or other carbon offsets, and the potential for future action by other federal agencies.

271

See, e.g.,

Standards of Performance for New, Reconstructed, and Modified Sources and Emissions Guidelines for Existing Sources: Oil and Natural Gas Sector Climate Review, 86 FR 63110 (Nov. 15, 2020).

112. Similarly, we believe it best to allow project sponsors to demonstrate that their proposed mitigation measures are verifiable and propose means for the Commission to monitor or track the proposed measures through the life of the project. This approach allows project sponsors to take advantage of existing monitoring programs and tailor verification and tracking to their chosen mitigation proposals and prevents the Commission from needing to establish a new monitoring program.

4. Opportunities for Mitigation

113. While project sponsors are free to propose any type of mitigation mechanism, the following are examples of mitigation mechanisms project sponsors may consider.

a. Market-Based Mitigation

114. Project sponsors may mitigate the GHG emissions of a proposed project through participation in one (or more) of the various types of carbon offset markets. Sponsors could, for example, purchase renewable energy credits, participate in a mandatory compliance market (if located in a state that requires participation in such a market), or participate in a voluntary carbon market.

i. Renewable Energy Credits

115. Renewable energy credits (REC) are tradeable, market-based

commodities that provide proof that one megawatt hour of electricity was generated from a renewable source and delivered to the grid. RECs legally convey the attributes of renewable electricity generation to their owner. While state or regional RECs may be traded on financial exchanges that typically meet state or regional guidelines, they are not limited by geographic boundaries—RECs can be purchased independently from electricity and can be matched with energy consumption.

272

For more information, see EPA Green Power Partnership,

Offsets and RECs: What's the Difference

(Feb. 2018),

https://www.epa.gov/sites/default/files/2018-03/documents/gpp_guide_recs_offsets.pdf.

116. Commenters argue that the Commission may not require RECs because unlike offsets, RECs pertain only to the use of electric power and are therefore not appropriate for upstream or downstream mitigation, do not mitigate or compensate for GHG emissions, and are not denominated in carbon dioxide (CO

) or CO

e, thus, they cannot represent any specific amount of avoided or reduced emissions.

273

Enbridge also states that in most instances, project sponsors will not qualify to purchase RECs under existing state programs.

274

While RECs may not represent a 100% offset per unit of GHG emitted, RECs do represent a decrease in GHG emissions from overall energy use and production, and we will consider them.

273

Enbridge Pre-Conference Comments at 6-7; Enbridge Technical Conference Comments at 42-46; Enbridge 2021 Comments at 145-148; INGAA Technical Conference Comments at 33.

274

Enbridge 2021 Comments at 23, 148 n. 406 (stating that the lack of a federal REC program coupled with the patchwork of state and regional, as well as voluntary and mandatory, REC programs brings into question whether project sponsors could participate in these existing programs).

ii. Mandatory Compliance Market Participation

117. The compliance market is a mandatory offset program regulated by national, regional, or provincial law and mandates CO

and GHG emission reduction requirements. Under this framework an allowance, which is an authorization for an entity to emit GHG emissions, is created. Allowances are generated and traded for regulatory compliance and are priced as a commodity based on supply and demand, regardless of project type.

118. A prime example of an existing, domestic compliance market is the Regional Greenhouse Gas Initiative (RGGI). RGGI is a cooperative effort by eleven Northeast and Mid-Atlantic states

275

to limit CO

emissions at certain electric power generators. Each region involved in RGGI has an established emissions budget (cap) and each

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