Notice2022-04536
Consideration of Greenhouse Gas Emissions in Natural Gas Infrastructure Project Reviews
Primary source
Metadata and text below are from the Federal Register, a public-domain U.S. government work. Always verify the official published version before relying on it for any legal matter.
Published
March 11, 2022
Issuing agencies
Energy DepartmentFederal Energy Regulatory Commission
Abstract
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.
Full Text
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[Federal Register Volume 87, Number 48 (Friday, March 11, 2022)]
[Notices]
[Pages 14104-14142]
From the Federal Register Online via the Government Publishing Office [<a href="http://www.gpo.gov">www.gpo.gov</a>]
[FR Doc No: 2022-04536]
[[Page 14103]]
Vol. 87
Friday,
No. 48
March 11, 2022
Part II
Department of Energy
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Federal Energy Regulatory Commission
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Consideration of Greenhouse Gas Emissions in Natural Gas Infrastructure
Project Reviewsotice of Decision; Notice
Federal Register / Vol. 87 , No. 48 / Friday, March 11, 2022 /
Notices
[[Page 14104]]
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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.
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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 <a href="http://www.ferc.gov">http://www.ferc.gov</a> 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,
<a href="/cdn-cgi/l/email-protection#6f240e1d060141230e1d1c00012f090a1d0c41080019"><span class="__cf_email__" data-cfemail="d893b9aab1b6f694b9aaabb7b698bebdaabbf6bfb7ae">[email protected]</span></a>
Eric Tomasi (Technical Information), Office of Energy Projects, Federal
Energy Regulatory Commission, 888 First Street NE, Washington, DC
20426, (202) 502-8097, <a href="/cdn-cgi/l/email-protection#8ecbfce7eda0dae1e3effde7cee8ebfceda0e9e1f8"><span class="__cf_email__" data-cfemail="b2f7c0dbd19ce6dddfd3c1dbf2d4d7c0d19cd5ddc4">[email protected]</span></a>
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.\1\ 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.\2\
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\1\ 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),
<a href="https://www.ipcc.ch/report/ar6/wg1/downloads/report/IPCC_AR6_WGI_SPM.pdf">https://www.ipcc.ch/report/ar6/wg1/downloads/report/IPCC_AR6_WGI_SPM.pdf</a> (IPCC Report).
\2\ See Sierra Club v. 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).
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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<INF>2</INF>e or more.\3\ 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.\4\ 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.\5\ 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.
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\3\ 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.
\4\ See, e.g., Grand Canyon Trust v. 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 v.
Peterson, 717 F.2d 1409, 1415 (D.C. Cir. 1983))); Found. for N. Am.
Wild Sheep v. 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.'').
\5\ See 42 U.S.C. 4331(a); 4332(c).
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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.\6\
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\6\ 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. v. 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 v. 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.
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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.\7\ The GHGs produced by fossil-fuel combustion are
carbon dioxide, methane, and nitrous oxide.
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\7\ IPCC Report at SPM-5. Other forces contribute to climate
change, such as agriculture, forest clearing, and other
anthropogenically driven sources.
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7. In 2017 and 2018, the U.S. Global Change Research Program \8\
issued its Climate Science Special Report: Fourth National Climate
Assessment, Volumes I and II.\9\ 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.\10\ 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.\11\ These impacts have
accelerated throughout the end of the 20th century and into the 21st
century.\12\
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\8\ 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.
\9\ U.S. Global Change Research Program, Climate Science Special
Report, Fourth National Climate Assessment [bond] Volume I (Donald
J. Wuebbles et al. eds) (2017), <a href="https://science2017.globalchange.gov/downloads/CSSR2017_FullReport.pdf">https://science2017.globalchange.gov/downloads/CSSR2017_FullReport.pdf</a>; 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), <a href="https://nca2018.globalchange.gov/downloads/NCA4_2018_FullReport.pdf">https://nca2018.globalchange.gov/downloads/NCA4_2018_FullReport.pdf</a> (USGCRP Report Volume II).
\10\ IPCC Report at SPM-5 to SPM-10.
\11\ USGCRP Report Volume II at 73-75.
\12\ See, e.g., USGCRP Report Volume II at 99 (describing
accelerating flooding rates in Atlantic and Gulf Coast cities).
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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.\13\ CEQ revised the
draft guidance in 2014,\14\ and issued final guidance in 2016.\15\
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.\16\
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\13\ CEQ, Draft NEPA Guidance on Consideration of the Effects of
Climate Change and Greenhouse Gas Emissions (Feb. 18, 2010), <a href="https://ceq.doe.gov/docs/ceq-regulations-and-guidance/20100218-nepa-consideration-effects-ghg-draft-guidance.pdf">https://ceq.doe.gov/docs/ceq-regulations-and-guidance/20100218-nepa-consideration-effects-ghg-draft-guidance.pdf</a>.
\14\ 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).
\15\ 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),
<a href="https://ceq.doe.gov/docs/ceq-regulations-and-guidance/nepa_final_ghg_guidance.pdf">https://ceq.doe.gov/docs/ceq-regulations-and-guidance/nepa_final_ghg_guidance.pdf</a> (2016 CEQ Guidance).
\16\ 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.'').
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9. CEQ rescinded the 2016 guidance in April 2017, as directed by
Executive Order 13783 Promoting Energy Independence and Economic
Growth,\17\ and issued revised draft guidance in June 2019.\18\ 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.\19\ 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.\20\
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\17\ Exec. Order No. 13783, 82 FR 16576 (Apr. 5, 2017).
\18\ Draft National Environmental Policy Act Guidance on
Consideration of Greenhouse Gas Emissions, 84 FR 30097 (June 26,
2019).
\19\ Exec. Order No. 13990, 86 FR 7037 (Jan. 20, 2021).
\20\ Notice of Rescission of Draft Guidance, 86 FR 10252 (Feb.
19, 2021).
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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.\21\ 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).\22\ 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.\23\ For indirect upstream, production-
related GHG emissions, Commission orders during that time period relied
on Department of Energy studies to calculate broad estimates.\24\ 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.\25\
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\21\ 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).
\22\ 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).
\23\ 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).
\24\ See, e.g., Columbia Gas Transmission, LLC, 158 FERC ]
61,046 at PP 116-119.
\25\ 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 v. FERC, 925 F.3d 510,
518 (D.C. Cir. 2019) (Birckhead).
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11. In 2017, the United States Court of Appeals for the District of
Columbia Circuit (D.C. Circuit) in Sierra Club v. FERC (Sabal Trail)
\26\ 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
[[Page 14106]]
transported by the pipeline or explain why the Commission could not do
so, and to discuss the significance of these emissions.\27\ On remand,
the Commission compared the estimated downstream GHG emissions from the
project to state and national GHG emission inventories.\28\ 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.\29\
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\26\ 867 F.3d 1357.
\27\ Id. at 1374.
\28\ Fla. Se. Connection, LLC, 164 FERC ] 61,099, at P 5 (2018).
\29\ Id. No party petitioned for judicial review of the
Commission's determination on remand.
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12. In 2018, the Commission stated in Dominion Transmission,
Inc.\30\ 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.\31\ 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.'' \32\ The
Commission reiterated that without an accepted methodology it could not
find whether a particular quantity of GHG emissions was
significant.\33\
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\30\ 163 FERC ] 61,128 (2018), pet. dismissed, Otsego 2000 v.
FERC, 767 F.App'x 19 (D.C. Cir. 2019) (unpublished opinion).
\31\ Id. PP 41-44, 61-62.
\32\ Id. P 44; see also Tenn. Gas Pipeline Co., LLC, 163 FERC ]
61,190, at PP 61-62 (2018).
\33\ Dominion Transmission, Inc., 163 FERC ] 61,128 at PP 67-70.
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13. However, in Birckhead, the D.C. Circuit rejected the
Commission's position that Sabal Trail is limited to the narrow facts
of that case. While the court in Birckhead acknowledged that downstream
emissions may not always be a foreseeable effect of natural gas
projects, it rejected the notion that downstream GHG emissions are a
reasonably foreseeable indirect effect of a natural gas project only if
a specific end destination is identified.\34\ The court further noted
that the Commission should attempt to obtain information on downstream
uses to determine whether downstream GHG emissions are a reasonably
foreseeable effect of the project.\35\
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\34\ Birckhead, 925 F.3d at 518-19.
\35\ Id. at 520.
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14. In 2021, in Northern Natural Gas Co., the Commission explained
that it had reconsidered its position that it was unable to assess the
significance of a project's GHG emissions or those emissions'
contribution to climate change.\36\ The Commission found that that
project's reasonably foreseeable GHG emissions--construction and
operation emissions only, as the project proposed no new capacity--
would not significantly contribute to climate change.\37\ Later in
2021, the D.C. Circuit further criticized the Commission's stance prior
to Northern Natural Gas Co. that it was unable to assess the
significance of a project's GHG emissions or those emissions'
contribution to climate change, holding that the Commission failed to
appropriately analyze the significance of three natural gas projects'
contribution to climate change using ``theoretical approaches or
research methods generally accepted in the scientific community,'' such
as the SCC tool.\38\
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\36\ 174 FERC ] 61,189, at P 29 (2021).
\37\ Id. PP 29-36.
\38\ Vecinos para el Bienestar de la Comunidad Costera v. FERC,
6 F.4th 1321, 1328 (D.C. Cir. 2021) (Vecinos) (citing 40 CFR
1502.21(c), which requires an EIS to include an evaluation of
impacts based upon theoretical approaches or research methods
generally accepted in the scientific community where the information
relevant to the reasonably foreseeable significant adverse impacts
cannot be obtained because the means to obtain it are not known).
The case is pending on remand with the Commission.
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D. Certificate Policy Statement Notices of Inquiry
15. On April 19, 2018, the Commission issued a Notice of Inquiry
(2018 NOI) \39\ seeking information and stakeholder perspectives to
help the Commission explore whether, and if so how, it should revise
its approach for determining whether proposed projects are consistent
with the public convenience and necessity under the currently effective
policy statement on the certification of new interstate natural gas
transportation facilities (Certificate Policy Statement).\40\ The 2018
NOI included a background section discussing how the legal standards
and historical context informed the creation of the Certificate Policy
Statement in 1999, how the Commission's evaluations under the
Certificate Policy Statement and under NEPA have evolved, and how
changed circumstances since 1999 have required the present review.\41\
Notably, the Commission sought input on whether, and if so how, the
Commission should adjust its evaluation of the environmental impacts of
a proposed project.
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\39\ 2018 NOI, 163 FERC ] 61,042.
\40\ Certification of New Interstate Natural Gas Pipeline
Facilities, 88 FERC ] 61,227 (1999), clarified, 90 FERC ] 61,128,
further clarified, 92 FERC ] 61,094 (2000). The Commission must
determine whether a proposed natural gas project is or will be
required by the present or future public convenience and necessity,
as that standard is established in NGA section 7. 15 U.S.C. 717f.
\41\ 2018 NOI, 163 FERC ] 61,042 at PP 5-50.
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16. In response to the 2018 NOI, the Commission received more than
3,000 comments from stakeholders including landowners; tribal, federal,
state, and local government officials; non-governmental organizations;
consultants, academic institutions, and think tanks; natural gas
producers, Commission-regulated companies, local distribution
companies, and industry trade organizations; electricity generators and
utilities; and others. Many comments addressed GHG emissions.
17. On February 18, 2021, the Commission issued a new, refreshed
Notice of Inquiry (2021 NOI),\42\ seeking comments to build upon the
existing record established by the 2018 NOI. The Commission posed
several updated questions relating to GHG emissions, including asking:
How the Commission could consider upstream impacts from natural gas
production and downstream end-use impacts; how the Commission should
determine the significance of a project's GHG emissions' contribution
to climate change; whether the NGA, NEPA, or another federal statute
authorize or mandate the use of the SCC analysis by the Commission; how
the Commission could determine whether a proposed project's GHG
emissions could be offset by reduced GHG emissions resulting from the
project's operations; and how the Commission could impose GHG emission
limits or mitigation to reduce the significance of impacts from a
proposed project on climate change.\43\
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\42\ Certification of New Interstate Natural Gas Facilities, 174
FERC ] 61,125 (2021).
\43\ Id. P 17.
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18. With respect to determining significance, the 2021 NOI sought
comment on (1) what type of metrics and models the Commission should
consider in determining significance, (2) whether any level of
emissions should be considered de minimis, and (3) how the SCC tool or
other tools could factor into determining significance.\44\
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\44\ Id. (citations omitted).
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19. The public comment period for the 2021 NOI closed on May 26,
2021.\45\ The Commission received over 35,000 comments and
approximately 150
[[Page 14107]]
unique comment letters from a wide range of stakeholders, as noted
above.
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\45\ See Notice Extending Time for Comments, Docket No. PL18-1-
000 (Mar. 31, 2021) (extending the original comment deadline from
April 26, 2021, to May 26, 2021).
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20. Comments relevant to this policy statement are addressed in
Section III below.
III. Statutory Authority/Obligations
A. NGA
21. Section 7 of the NGA authorizes the Commission to issue
certificates of public convenience and necessity for the construction
and operation of facilities transporting natural gas in interstate
commerce.\46\ The Commission does not have authority to regulate
intrastate transportation facilities or other facilities that affect
interstate transportation, such as those used for the production,
gathering, or local distribution of natural gas. Congress did not
displace state authority over such subjects.\47\
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\46\ 15 U.S.C. 717f.
\47\ NGA section 1(b) states that Commission authority applies
to interstate transportation of natural gas and sales for resale,
``but shall not apply to any other transportation or sale of natural
gas or to the local distribution of natural gas or to the facilities
used for such distribution or to the production or gathering of
natural gas.'' Id. 717(b).
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22. Section 3(a) of the NGA provides for federal jurisdiction over
the siting, construction, and operation of facilities used to import or
export gas.\48\ To date, the Commission has exercised section 3
authority to authorize: (1) LNG terminals located at the site of import
or export and (2) the site and facilities at the place of import/export
where a pipeline crosses an international border.\49\ Additionally, NGA
section 3(e) states that ``[t]he Commission shall have the exclusive
authority to approve or deny an application for the siting,
construction, expansion, or operation of an LNG terminal.'' \50\
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\48\ The 1977 Department of Energy Organization Act (42 U.S.C.
7151(b)) placed all section 3 jurisdiction under the Department of
Energy. The Secretary of Energy subsequently delegated authority to
the Commission to ``[a]pprove or disapprove the construction and
operation of particular facilities, the site at which such
facilities shall be located, and with respect to natural gas that
involves the construction of new domestic facilities, the place of
entry for imports or exit for exports.'' Department of Energy
Delegation Order No. 00-004.00A, section 1.21A (May 16, 2006).
\49\ In addition to pipelines that cross the international
border with Canada and Mexico, the Commission has also asserted
authority over the portions of subsea pipelines planned to cross the
``border'' of the Exclusive Economic Zone between the U.S. and the
Bahamas. See, e.g., Tractebel Calypso Pipeline, LLC, 106 FERC ]
61,273 (2004), vacated, Calypso U.S. Pipeline, LLC, 137 FERC ]
61,098 (2011).
\50\ 15 U.S.C. 717b(e)(1).
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23. Both NGA sections 7 and 3 authorize the Commission to attach
terms and conditions to its authorization.\51\ Courts have interpreted
these provisions broadly and given the Commission latitude in deciding
what types of mitigation to require.\52\ In issuing authorizations, the
Commission has required project sponsors to comply with conditions to
prevent or mitigate project impacts on environmental resources.\53\
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\51\ Id. 717f(e) (``The Commission shall have the power to
attach to the issuance of the certificate and to the exercise of the
rights granted thereunder such reasonable terms and conditions as
the public convenience and necessity may require.''); see also id.
717b(a) (stating that the Commission may ``grant such application,
in whole or in part, with such modification and upon such terms and
conditions as the Commission may find necessary or appropriate'');
id. 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'').
\52\ See Twp. of Bordentown v. FERC, 903 F.3d 234, 261 n.15 (3d
Cir. 2018) (concluding that the Commission's authority to enforce
any required remediation is amply supported by provisions of the
NGA); Sabal Trail, 867 F.3d at 1374 (holding that the Commission has
legal authority to mitigate reasonably foreseeable indirect
effects).
\53\ See, e.g., Atl. Coast Pipeline, LLC, 161 FERC ] 61,042, at
app. A (2017), on reh'g, 164 FERC ] 61,100 (2018).
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B. NEPA
24. NEPA and its implementing regulations require agencies, before
taking or authorizing a major federal action that may significantly
affect the quality of the human environment, to take a ``hard look'' at
the environmental consequences of the proposed action and disclose
their analyses to the public by preparing an EIS.\54\ Alternatively,
agencies can first prepare an Environmental Assessment (EA) for a
proposed action that is not likely to have significant effects or when
the significance is unknown, to determine whether an EIS is necessary
for a particular action.\55\ Depending on the outcome of the EA,
agencies can either prepare an EIS or issue a finding of no significant
impact.\56\
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\54\ 42 U.S.C. 4332(2)(C); 40 CFR 1502.3; see Balt. Gas & Elec.
Co. v. Nat. Res. Def. Council, Inc., 462 U.S. 87, 97 (1983)
(discussing the twin aims of NEPA).
\55\ 40 CFR 1501.5, 1508.1(h).
\56\ 40 CFR 1508.1(l) (defining a finding of no significant
impact as a document that briefly presents the reasons why an action
that is not otherwise categorically excluded under Sec. 1501.4 will
not have a significant effect on the human environment and for which
an EIS will therefore not be prepared).
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25. Previous CEQ regulations and court cases have examined a
proposed project's ``context'' and ``intensity'' or the severity of the
impact as factors for determining what constitutes a significant
effect.\57\ In assessing significance, Commission staff considers, for
each resource, the duration of the impact as well as the geographic,
biological, or social context in which the effects would occur, and the
intensity (e.g. severity) of the impact.\58\ This analysis may draw on
both qualitative and quantitative information.\59\ Using both types of
data, the Commission routinely makes significance determinations for
impacts to various resources from natural gas projects.\60\
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\57\ Vieux Carre Prop. Owners, Residents & Assocs., Inc. v.
Pierce, 719 F.2d 1272, 1279 (5th Cir. 1983) (stating there is ``no
hard and fast definition of `significant' '' but considering the
proposed project's context in assessing whether a finding of no
significance impact was reasonable). The regulations implementing
NEPA previously addressed the term ``significantly,'' but that
provision was removed by amendments effective September 14, 2020 and
replaced with 40 CFR 1501.3(b). ``Whether a project has significant
environmental impacts, thus triggering the need to produce an EIS,
depends on its `context' (region, locality) and `intensity'
(`severity of impact').'' Nat'l Parks Conservation Ass'n v.
Semonite, 916 F.3d 1075, 1082 (D.C. Cir.) (quoting 40 CFR 1508.27
(2018)), amended in part by 925 F.3d 500 (D.C. Cir. 2019). The new
40 CFR 1501.3(b) calls for agencies to consider the ``potentially
affected environment and degree of the effects of the action'' and
to consider the short-term, long-term, beneficial, and adverse
effects, and effects on public safety and those that would violate
laws.
\58\ See, e.g. Final EIS for the Alaska LNG Project, Docket No.
CP17-178-000, at 4-1.
\59\ See Sabal Trail, 867 F.3d at 1371 (``The EIS also gave the
public and agency decisionmakers the qualitative and quantitative
tools they needed to make an informed choice for themselves. NEPA
requires nothing more.'').
\60\ See, e.g., 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),
order on reh'g, 161 FERC ] 61,250 (2017), petition denied sub nom.,
Allegheny Def. Project v. FERC, 964 F.3d 1 (D.C. Cir. 2020); see
also infra note 61; see also Magnum Gas Storage, LLC, 134 FERC ]
61,197, at P 115 (2011) (explaining that ```significantly,' as used
in NEPA, requires considerations of both context and intensity,
which varies with the setting of each proposed action.'').
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26. In evaluating whether an impact is significant, the Commission
determines whether ``it would result in a substantial adverse change in
the physical environment.'' \61\ In making that determination, the
Commission considers available evidence, giving that evidence such
weight as it deems appropriate using its experience, judgment, and
expertise.\62\ Notably,
[[Page 14108]]
NEPA does not require that the studies, metrics, and models on which an
agency relies be universally accepted or otherwise uncontested.\63\
Instead, NEPA permits agencies to rely on the best available evidence,
quantitative and qualitative, even where that evidence has certain
limitations when assessing the significance of their actions,\64\ and
an agency's determination is entitled to deference.\65\
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\61\ N. Nat. Gas Co., 174 FERC ] 61,189, at P 32 (citing Magnum
Gas Storage, LLC, 134 FERC ] 61,197 at P 114 (``[A]n impact was
considered to be significant if it would result in a substantial
adverse change in the physical environment or natural condition and
could not be mitigated to less-than-significant level.'')).
\62\ See, e.g., Tex. LNG Brownsville LLC, 169 FERC ] 61,130, at
P 56 (2019) (``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.''), order on reh'g, 170 FERC ] 61,139, at
P 32 (2020), remanded on other grounds, Vecinos, 6 F.4th 1321; Final
EIS for the Alaska LNG Project, Docket No. CP17-178-000, at ES-4
(Mar. 2020) (explaining the significant, long-term to permanent
project impacts from the loss of thousands of acres of permafrost
from construction that would permanently alter hydrology and
vegetation within and past the project footprint).
\63\ Sierra Club v. U.S. Dep't of Transp., 753 F.2d 120, 128
(D.C. Cir. 1985) (``It is clearly within the expertise and
discretion of the agency to determine proper testing methods.'');
see also Hughes River Watershed Conservancy v. Johnson, 165 F.3d
283, 289 (4th Cir. 1999) (``Agencies are entitled to select their
own methodology as long as that methodology is reasonable. The
reviewing court must give deference to an agency's decision.'').
\64\ See Spiller v. White, 352 F.3d 235, 244 n.5 (5th Cir. 2003)
(rejecting petitioner's contention that the significance
determination must be objective, factual, and quantitative and
should not involve any qualitative judgment calls).
\65\ See La. Crawfish Producers Ass'n-W. v. Rowan, 463 F.3d 352,
355 (5th Cir. 2006) (NEPA-related decisions are accorded a
considerable degree of deference); Spiller v. White, 352 F.3d at 244
n.5 (``We should note that our deference to the [l]ead [a]gencies[']
fact-finding and conclusions includes deference to their judgment as
to whether any particular environmental impact of the proposed
pipeline rises to the level of significance''); Powder River Basin
Res. Council v. U.S. Bureau of Land Mgmt., 37 F.Supp. 3d 59, 74
(D.D.C. 2014) (agencies are afforded discretion to use their
expertise to determine the best method to evaluate the significance
of an impact to a particular resource, so long as that method is
reasonable).
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27. In addition to determining whether its actions may
significantly affect the quality of the human environment, NEPA
requires the Commission to consider whether there are steps that could
be taken to mitigate any adverse environmental consequences.\66\ While
NEPA is a procedural statute and does not require a federal agency to
reject a proposed project with significant adverse effects or take
action to mitigate adverse effects,\67\ an agency may require
mitigation of impacts as a condition of its permitting or approval,\68\
and the Commission routinely does so.\69\
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\66\ Robertson v. Methow Valley Citizens Council, 490 U.S. 332,
351 (1989) (``To be sure, one important ingredient of an EIS is the
discussion of steps that can be taken to mitigate adverse
environmental consequences.'').
\67\ Id. at 352 (``There is a fundamental distinction, however,
between a requirement that mitigation be discussed in sufficient
detail to ensure that environmental consequences have been fairly
evaluated, on the one hand, and a substantive requirement that a
complete mitigation plan be actually formulated and adopted, on the
other.'').
\68\ Final Guidance for Federal Departments and Agencies on the
Appropriate Use of Mitigation and Monitoring and Clarifying the
Appropriate use of Mitigated Findings of No Significant Impact, 76
FR 3843, 3848 (Jan. 21, 2011).
\69\ See, e.g., Columbia Gas Transmission, LLC, 170 FERC ]
61,045, at P 66, app. (2020) (conditioning certificate authority on
site-specific mitigation measures when crossing abandoned mine
lands, including the management and disposal of contaminated
groundwater, and mitigation measures for acid mine drainage);
PennEast Pipeline Co., LLC, 170 FERC ] 61,198, at PP 29-30, app. A
(2020) (conditioning certificate authority on mitigation of
construction impacts on karst features); Atl. Coast Pipeline, LLC,
161 FERC ] 61,042 at app. A (conditioning certificate authority on
the mitigation of construction impacts on karst features and on a
nearby inn and mitigation of impacts from the discovery of invasive
aquatic species during construction); Port Arthur LNG, LP, 115 FERC
] 61,344, at PP 68-71, app. A (conditioning sections 3 and 7
authority on the mitigation of construction impacts on aquatic
resources and wetlands), order on reh'g, 117 FERC ] 61,213 (2006),
vacated, 136 FERC ] 61,196 (2011).
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IV. Discussion
A. Quantifying GHG Emissions and Determining Significance
28. Consistent with CEQ regulations,\70\ the Commission will
quantify a project's GHG emissions that are reasonably foreseeable and
have a reasonably close causal relationship to the proposed action,
including those effects that occur at the same time and place as the
proposed action and effects that are later in time or farther removed
in distance from the proposed action. This will include GHG emissions
resulting from construction and operation of the project \71\ as well
as, in most cases, GHG emissions resulting from the downstream
combustion of transported gas.\72\
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\70\ 40 CFR 1508.1(g) (defining the effects or impacts that must
be considered when conducting a review under NEPA).
\71\ Emissions quantification also includes loss of carbon
storage/sinks through land use conversions, forest clearing, wetland
conversions, etc.
\72\ As discussed below, the vast majority of all natural gas
consumed in the United States is combusted. See infra note 101.
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29. The Commission will consider all evidence in the record
relating to a project's estimated GHG emissions,\73\ utilization rate,
or offsets: Estimates presented by project sponsors, as well as
opposing evidence from other parties. Going forward, in determining the
level of GHG emissions attributed to a project, the Commission will
estimate a project's GHG emissions based on a projection of what amount
of project capacity will be actually used (projected utilization rate),
as opposed to assuming 100% utilization.\74\ The Commission will also
consider evidence of factors expected to reduce or offset the estimated
direct or reasonably foreseeable downstream emissions of the project.
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\73\ Additionally, the Commission will consider evidence
regarding whether certain emissions associated with a proposed
project, such as upstream and downstream emissions, are reasonably
foreseeable.
\74\ See Certification of New Interstate Natural Gas Pipeline
Facilities, 178 FERC ] 61,107, at P 55 (2022) (explaining that
project sponsors are encouraged to provide the Commission with
information on estimated utilization rates and the intended end use
of gas to demonstrate project need).
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1. Categories of Emissions
30. CEQ regulations implementing NEPA require agencies to consider
effects or impacts that ``are reasonably foreseeable and have a
reasonably close causal relationship to the proposed action . . .
including those effects that occur at the same time and place as the
proposed action . . . and may include effects that are later in time or
farther removed in distance for the proposed action . . . .'' \75\ A
``but for'' causal relationship is insufficient to make an agency
responsible for a particular effect,\76\ and effects should not be
considered if they are the ``product of a lengthy causal chain.'' \77\
Further, effects to be considered do not include those that the agency
has no ability to prevent due to its limited statutory authority or
would occur regardless of the proposed action.\78\ Regarding reasonable
foreseeability, courts have found that an impact is reasonably
foreseeable if it is ``sufficiently likely to occur that a person of
ordinary prudence would take it into account in reaching a decision.''
\79\ Although courts have held that NEPA requires ``reasonable
forecasting,'' \80\ an agency ``is not required to engage in
speculative analysis'' \81\ or ``to do the impractical, if
[[Page 14109]]
not enough information is available to permit meaningful
consideration.'' \82\
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\75\ 40 CFR 1508.1(g).
\76\ Id. Sec. 1508.1(g)(2); see also U.S. Dep't of Transp. v.
Pub. Citizen, 541 U.S. 752, 767 (2004) (Pub. Citizen) (finding that
``NEPA requires `a reasonably close causal relationship' between the
environmental effect and the alleged cause'' in order ``to make an
agency responsible for a particular effect under NEPA'' (quoting
Metro. Edison Co. v. People Against Nuclear Energy, 460 U.S. 766,
774 (1983) (Metro. Edison Co.))).
\77\ 40 CFR 1508.1(g)(2); see also Metro. Edison Co., 460 U.S.
at 774 (finding that ``[s]ome effects that are `caused by' a change
in the physical environment in the sense of `but for' causation,''
will not fall within NEPA if ``the causal chain is too
attenuated'').
\78\ 40 CFR 1508.1(g)(2); see also Pub. Citizen, 541 U.S. at 770
(``[W]here an agency has no ability to prevent a certain effect due
to its limited statutory authority over the relevant actions, the
agency cannot be considered a legally relevant `cause' of the
effect.'').
\79\ EarthReports, Inc. v. FERC, 828 F.3d 949, 955 (DC Cir.
2016) (citations omitted); see also Sierra Club v. Marsh, 976 F.2d
763, 767 (1st Cir. 1992).
\80\ N. Plains Res. Council, Inc. v. Surface Transp. Bd., 668
F.3d 1067, 1079 (9th Cir. 2011) (quoting Selkirk Conservation All.
v. Forsgren, 336 F.3d 944, 962 (9th Cir. 2003)).
\81\ Id. at 1078.
\82\ Id. (quoting Envtl. Prot. Info. Ctr. v. U.S. Forest Serv.,
451 F.3d 1005, 1014 (9th Cir. 2006)).
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31. As discussed below, the Commission proposes to:
<bullet> Consider direct emissions of a project a reasonably
foreseeable effect;
<bullet> Find that an NGA section 3 export facility project is not
the legally relevant cause of upstream and downstream emissions; \83\
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\83\ EarthReports, Inc. v. FERC, 828 F.3d at 955 (citing Sierra
Club v. FERC, 827 F.3d 36, 47, 59, 68 (D.C. Cir. 2016) (Freeport).
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<bullet> Consider on a case-by-case basis whether downstream
emissions are a reasonably foreseeable effect of an NGA section 7
interstate project; and
<bullet> Consider on a case-by-case basis whether upstream
emissions are a reasonably foreseeable effect of an NGA 7 project.
a. Direct Emissions
32. Several commenters assert that the Commission must consider
fugitive emissions from the transportation of gas.\84\ New Jersey
Conservation Foundation, Sabin Center for Climate Change Law (Sabin
Center), The Watershed Institute, Clean Air Council, PennFuture, and
New Jersey League of Conservation Voters (collectively, New Jersey
Conservation Foundation) argue that natural gas leakage from both
pipeline operation and natural gas production is worse than combustion
because methane has a higher global warming potential than carbon
dioxide.\85\
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\84\ See, e.g., Egan Millard 2021 Comments at 3; New Jersey
Conservation Foundation 2021 Comments at 21; Shayna Gleason 2021
Comments at 2.
\85\ New Jersey Conservation Foundation 2021 Comments at 21.
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33. As the Commission has long held, direct GHG emissions from the
project's short-term construction \86\ and long-term operational
activities \87\ are an effect of the proposed project. Under current
Commission regulations, the project sponsor provides an estimate of
construction emissions and an estimate of the project's potential
operational emissions, including fugitive emissions from both pipeline
and aboveground facilities, in its application for Commission
authorization.\88\
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\86\ Construction emissions include emissions from gasoline- and
diesel-powered construction equipment.
\87\ Operational emissions include emissions from combustion
units at compressor stations and fugitive leaks from compressor
stations, meter/valve stations, and the pipeline.
\88\ The project sponsor provides emissions information in
Resource Report No. 9. 18 CFR 380.12(k). Operational emissions are
also estimated in the project's air permit application, which is
typically submitted to the state agency with delegated Clean Air Act
authority. Further, the Commission's guidance manual for NGA
certificate applications instructs project sponsors to provide the
GHGs in tons per year for the construction and operation of the
proposed project. See Guidance Manual for Environmental Report
Preparation for Applications Filed under the NGA, Volume I, at 4-
123, 4-125 to 4-127 (Guidance Manual).
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b. Downstream Emissions
34. Some commenters argue that the Commission must consider the
downstream emissions of natural gas projects,\89\ including fugitive
emissions.\90\ In contrast, other commenters generally assert that the
Commission should not consider downstream emissions, or at most, should
only do a qualitative assessment of downstream emissions, because they
are not reasonably foreseeable impacts or do not have a close causal
relationship under NEPA to gas transportation.\91\
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\89\ See, e.g., Food and Water Watch 2021 Comments at 1; New
Jersey Conservation Foundation 2021 Comments at 19; Attorneys
General of Massachusetts, Illinois, Maryland, New Jersey, Rhode
Island, Washington, and the District of Columbia (Attorneys General
of Massachusetts et al.) 2018 Comments at 12-17.
\90\ For example, the Massachusetts PipeLine Awareness Network
states that the Commission should consider fugitive emissions from
the distribution and burning of transported gas. Massachusetts
PipeLine Awareness Network 2021 Comments at 2; see also, e.g., Egan
Millard 2021 Comments at 3; Shayna Gleason 2021 Comments at 2.
\91\ See, e.g., American Petroleum Institute (API) Technical
Conference Comments at 3-5 (stating the Commission and developers
cannot accurately forecast downstream emissions due to lack of
knowledge of the end use of the gas, variability in utilization
rates and regulatory requirements, and unpredictable changes in
supply and demand, among other factors); Boardwalk Pipeline Partners
LP (Boardwalk) Technical Conference Comments at 21; Enbridge Gas
Pipelines (Enbridge) Technical Conference Comments at 11, 25-26;
Interstate Natural Gas Association of America (INGAA) 2021 Comments
at 58-60; The Williams Companies, Inc. (Williams) 2021 Comments at
37-38; Natural Gas Supply Association (NGSA) 2018 Comments at 15-16.
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35. As discussed above, in August 2017, the D.C. Circuit issued
Sabal Trail, which involved a greenfield pipeline project that would
deliver all gas transported by the project to specific gas-fired
generating plants. The D.C. Circuit found that downstream emissions
from the use of the transported natural gas were an indirect,
reasonably foreseeable effect of the proposed pipeline and that in the
circumstances of that case--where the vast majority of throughput on
the proposed project was destined for a limited number of specifically
identified electric generation facilities--the downstream GHG emissions
could be reasonably quantified by the Commission.\92\
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\92\ The court concluded ``that the EIS for the Southeast Market
Project should have either given a quantitative estimate of the
downstream greenhouse emissions that will result from burning the
natural gas that the pipelines will transport or explained more
specifically why it could not have done so.'' Sabal Trail, 867 F.3d
at 1374.
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36. The D.C. Circuit reiterated this determination in two
subsequent cases. First, in Birckhead, the court rejected the claim
that downstream emissions are only a foreseeable effect in factual
circumstances akin to Sabal Trail, i.e., where all transported gas will
be burned at specifically identified destinations, but also rejected
the argument that downstream emissions are always a foreseeable effect
of a natural gas certificate project.\93\ Then, in Allegheny Defense
Project v. FERC,\94\ the court stated that the downstream emissions of
a project designed to deliver gas into large interstate pipeline
systems, which in turn deliver gas to 16 states, are an indirect effect
of the project.\95\
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\93\ Birckhead, 925 F.3d at 518-20 (criticizing the Commission
for not attempting to obtain data on downstream uses).
\94\ 932 F.3d 940 (DC Cir. 2019).
\95\ Id. at 945-46.
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37. INGAA and others read the Supreme Court's Public Citizen
decision as requiring an agency to consider an environmental effect
only when the agency has the authority to control the outcome and note
that the Commission has no authority to regulate the end use (or
production) of natural gas.\96\ INGAA states that attempting to
regulate downstream (or upstream) activities would invade the
jurisdiction of other regulators, that most projects will not result in
reasonably foreseeable downstream GHG emissions like those in Sabal
Trail, and thus, downstream emissions should only be considered on a
case-by-case basis.\97\ INGAA suggests the Commission look for guidance
to Center for Biological Diversity v. U.S. Army Corps of Engineers,\98\
which criticizes Sabal Trail as ``breezing past . . . statutory limits
and precedents . . . clarifying what effects are cognizable under
NEPA.'' \99\
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\96\ See, e.g., INGAA 2021 Comments at 50-51.
\97\ INGAA 2021 Comments at 49-51, 57; 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'').
\98\ 941 F.3d 1288 (11th Cir. 2019) (Center for Biological
Diversity).
\99\ Id. at 1300 (citing Pub. Citizen, 541 U.S. 752 and Metro.
Edison Co., 460 U.S. 766).
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38. Given that data show that the vast majority of consumed gas is
ultimately combusted,\100\ there appears to be a
[[Page 14110]]
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.
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\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), <a href="https://www.eia.gov/totalenergy/data/monthly/pdf/mer.pdf">https://www.eia.gov/totalenergy/data/monthly/pdf/mer.pdf</a>; 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).
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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\
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\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).
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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\
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\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.
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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\
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\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. v. FERC, 828
F.3d at 956 (same); Sabal Trail, 867 F.3d at 1372 (explaining
Freeport).
\109\ Freeport, 827 F.3d at 48.
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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\
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\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.
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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.
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\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 v. FERC, 485
F.App'x 472, 474-75 (2d Cir. 2012) (unpublished opinion); see also
Adelphia Gateway, LLC, 169 FERC ] 61,220, at P 243 (2019), order on
reh'g, 171 FERC ] 61,049, at P 89 (2020).
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2. Calculating GHG Emissions
44. To calculate operational emissions, project sponsors should
continue to follow the existing guidance outlined in section 4.9.1.3 of
the Commission's Guidance Manual for Environmental Report Preparation
for
[[Page 14111]]
Applications Filed under the NGA.\115\ However, under this policy
statement, for purposes of assessing the impact of a project's GHG
emissions on climate change, the Commission will consider operational
GHG emissions calculated based on a projected utilization rate for the
project, as described below.\116\
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\115\ We note that thresholds for Clean Air Act and state air
permits are typically based on the regulated source's potential to
emit, or the maximum capacity of a stationary source to emit any air
pollutant under its physical and operational design, rather than its
actual emissions, and that air permits themselves are expressed in
potential to emit. See 40 CFR 70.2. This policy statement does not
apply to any other air pollutants than GHGs. For all other air
pollutants, we will continue to evaluate a project's air quality
impacts based on its potential to emit.
\116\ See infra section III.A.2.a.
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45. Additionally, the Commission recognizes that there may be other
factors that might serve to reduce a proposed project's climate
impacts. For example, the installation of emission-reduction technology
or purchase of offsets by downstream users would reduce the impacts.
Thus, to enable the Commission's use of the best estimate of a
project's GHG emissions, project sponsors are encouraged to calculate
project GHG emissions using a projected utilization rate and submit
evidence of any other factors that might impact a project's net
emissions such as the factors identified by commenters below.
46. Commenters recommend that the Commission consider factors that
might impact a project's net emissions, such as (1) whether the
transported gas will phase out use of a more carbon-intensive energy
source, like coal or fuel oil, and will prevent the use of more carbon-
intensive energy sources in the future; (2) whether the pipeline will
transport gas that would otherwise be transported by vehicles, thereby
reducing the emissions from transporting the gas; (3) whether the
proposed project will transport gas volumes that would have otherwise
been delivered to the same consumers through a different pipeline or
may ultimately end up transporting fuel blends including renewable
natural gas or hydrogen; (4) whether the project sponsor will purchase
offsets to counter project emissions; or (5) whether the project may be
backed by a local distribution company serving customer demand in
states with established emissions caps.\117\ INGAA states that in the
absence of reliable and verifiable predictive models to the contrary,
the requirement of reasonable foreseeability arguably dictates that the
Commission cannot adopt any default assumption that a natural gas
infrastructure project will increase (rather than decrease, or leave
unchanged) net global GHG emissions, and that at minimum, the
Commission would have to provide a rational justification for any such
assumption.\118\ By contrast, New Jersey Conservation Foundation and
others contend that the Commission should consider whether the project
may be displacing renewable energy sources, thereby increasing GHG
emissions.\119\
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\117\ See, e.g., American Gas Association (AGA) Technical
Conference Comments at 28, 40; API Technical Conference Comments at
3; Boardwalk Technical Conference Comments at 23 (stating that the
Commission should rely on local distribution companies' air permits
to determine GHG emissions); Enbridge Technical Conference Comments
at 31-34; Hon. Joseph T. Kelliher Technical Conference Comments at
5-6 (Commissioner Kelliher, Principal at Three Acorns, was a
panelist at the GHG Technical Conference on Panel 1.); INGAA
Technical Conference Comments at 17-18 (suggesting the net emissions
analysis must be undertaken on a global level); Kinder Morgan
Entities (Kinder Morgan) Technical Conference Comments at 12-15;
National Grid Gas Companies Technical Conference Comments at 3-7
(describing the Distributed Infrastructure Solution that it has
developed in coordination with the State of New York); Williams
Technical Conference Comments at 7-8; Charles River Associates 2021
Comments at 4-5; Ohio Environmental Council 2021 Comments at 3. See
Environmental Assessment for the Iroquois Gas Transmission System,
L.P. (Iroquois) Enhancement by Compression Project, Docket No. CP20-
48-000, at B-110 (Sept. 30, 2020) (citing Iroquois' end-use GHG
analysis that projected greater GHG emissions if the project was not
built under scenarios where the energy needs of all new buildings
are met by fuel oil as opposed to gas supplied by the project). One
industrial end user expresses concern about the potential of
integrating renewable natural gas due to concerns about pipeline
integrity or increased costs. American Forest and Paper Association
and Process Gas Consumers Group (collectively, American Forest)
Technical Conference Comments at 13-14.
\118\ INGAA Technical Conference Comments at 19.
\119\ See, e.g., New Jersey Conservation Foundation 2021
Comments at 23.
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47. INGAA and other commenters strongly urge the Commission to
calculate a project's downstream emissions, if at all, based on the
likely utilization rate of the proposed project, instead of relying on
a full-burn estimate.\120\
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\120\ See, e.g., Enbridge Technical Conference Comments at 12,
29-30; Hon. Joseph T. Kelliher Technical Conference Comments at 5-6;
INGAA Technical Conference Comments at 15-16 (describing an analysis
it commissioned concluding that in 2020, the maximum utilization on
an average annual basis for any of the pipeline ``corridors''
between different regions is not higher than 65% and it is over 50%
only for 7 of the 30 regional corridors); TC Energy Technical
Conference Comments at 18; Charles River Associates 2021 Comments at
6; INGAA 2021 Comments at 58; 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.
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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\
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\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.
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a. Projected Utilization Rate
49. In previous environmental documents and certificate orders, the
Commission has disclosed a project's operational emissions \126\ and
estimates
[[Page 14112]]
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\
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\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 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).
\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.
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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:
<bullet> Expected utilization data from project shippers;
<bullet> Historical usage data; \129\
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\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.
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<bullet> Demand projections;
<bullet> 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.
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\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).
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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\
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\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).
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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\
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\136\ See Magnum Gas Storage, LLC, 134 FERC ] 61,197 at P 114
(``[A]n impact was considered to be significant if it would result
in a substantial adverse change in the physical environment or
natural condition and could not be mitigated to less-than-
significant level.'').
\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.
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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\
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\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
[[Page 14113]]
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\
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\140\ See, e.g., Sabin Center 2018 Comments at 8-9.
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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\
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\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.
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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\
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\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.
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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\
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\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.
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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<INF>2</INF>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\
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\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.
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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\
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\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.
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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\
---------------------------------------------------------------------------
\155\ CEQ 2021 Comments at 1.
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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
[[Page 14114]]
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\
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\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.
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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\
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\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.
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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\
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\163\ EDF 2021 Comments at 9-12, 16.
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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.
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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\
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\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.
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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\
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\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.
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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\
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\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.
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[[Page 14115]]
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\
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\178\ CEQ 2021 Comments at 2. C.f. Louisiana v. 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.
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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\
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\183\ Public Interest Organizations 2021 Comments at 58.
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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\
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\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.
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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\
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\189\ New Jersey Conservation Foundation 2021 Comments at 24;
see also EDF 2021 Comments at 6-7.
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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\
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\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.
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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\
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\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.
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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<INF>2</INF>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<INF>2</INF>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<INF>2</INF>e or greater will be presumed to have a
significant effect, unless record evidence refutes that
[[Page 14116]]
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<INF>2</INF>e threshold.
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\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.
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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\
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\198\ 15 U.S.C. 717b(a).
\199\ Id. 717f(c), (e).
\200\ Distrigas Corp. v. FPC, 495 F.2d 1057, 1065 (D.C. Cir.).
\201\ Atl. Ref. Co. v. 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 v. 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.'').
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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\
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\204\ See supra PP 34-37.
\205\ See supra P 42.
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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\
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\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.
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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\
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\207\ EPA 2021 Comments at 6.
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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\
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\208\ See supra PP 23-25.
\209\ Spiller v. White, 352 F.3d at 244 n.5.
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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 ([deg]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 [deg]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 [deg]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 [deg]C of
warming ``causes clearly discernible increases in the intensity and
frequency of hot extremes, including heatwaves (very likely), and heavy
precipitation
[[Page 14117]]
(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.
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\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).
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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<INF>2</INF>e.
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\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.
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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<INF>2</INF>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<INF>2</INF>e would be subject to PSD requirements
regardless of whether there was an increase in the emissions of any
other pollutant.\220\
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\220\ EPA also planned a Step 3 to further reduce the threshold,
although not below 50,000 tons per year of CO<INF>2</INF>e. The
Supreme Court struck down relevant portions of the Tailoring Rule
before EPA finalized Step 3.
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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<INF>2</INF>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.
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\221\ Tailoring Rule, 75 FR at 31533-80.
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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.
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\222\ Util. Air Regul. Grp. v. EPA, 573 U.S. 302, 320 (2014).
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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<INF>2</INF>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<INF>2</INF>e per
year for stationary
[[Page 14118]]
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\
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\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), <a href="http://www.aqmd.gov/docs/default-source/ceqa/handbook/greenhouse-gases-">http://www.aqmd.gov/docs/default-source/ceqa/handbook/greenhouse-gases-</a>
(ghg)-ceqa-significance-thresholds/ghgboardsynopsis.pdf?sfvrsn=2.
\225\ Id. at 4; CEQA Proposed Interim Thresholds at attach. A.
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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.
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\226\ Currently, two pending court cases challenge use of the
IWG's interim values by federal agencies. Mo. v. Biden, ---- F.
Supp. 3d ----, 2021 WL 3885590 (E.D. Mo. Aug. 31, 2021), appeal
filed, No. 21-3013 (8th Cir.); La. v. Biden, No. 21-cv-1074-JDC-KK
(W.D. La).
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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\
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\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. v. U.S. Dep't of Interior, 588 F.3d
718, 727 (9th Cir. 2009); see also Nat'l Parks & Conservation Ass'n
v. 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'').
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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.
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\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'').
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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.
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\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).
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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
[[Page 14119]]
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\
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\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 v. 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.
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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\
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\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. v. 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 v. FPC,
425 U.S. at 669-70; State of Cal. v. Southland Royalty Co., 436 U.S.
519, 523 (1989); ONEOK, Inc. v. Learjet, Inc., 575 U.S. 373, 378,
384-85 (2015); ANR Pipeline Co. v. 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).
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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\
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\242\ Sabal Trail, 867 F.3d at 1374.
\243\ Transco, 365 U.S. at 17; see also NAACP v. FPC, 425 U.S.
at n.6 (stating that the Commission has the authority to consider
conservation and environmental issues under the NGA's public
interest determination). See Certification of New Interstate Natural
Gas Pipeline Facilities, 178 FERC ] 61,107 at PP 71-72.
\244\ 15 U.S.C. 717f(e); see also id. 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.'').
\245\ For examples where the Commission has conditioned approval
of natural gas projects on mitigation of adverse impacts, see supra
note 69.
\246\ See Twp. of Bordentown v. FERC, 903 F.3d at 261 n.15
(concluding that the Commission's authority to enforce any required
remediation is amply supported by provisions of the NGA); Sabal
Trail, 867 F.3d at 1374 (holding that the Commission has legal
authority to mitigate reasonably foreseeable indirect effects).
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104. Regarding claims that the Commission cannot mandate mitigation
of downstream emissions because those emissions are outside the
Commission's jurisdiction, we recognize, as many commenters assert,
that the Commission does not have the statutory authority to impose
conditions on downstream users or other entities outside the
Commission's jurisdiction, such as production, gathering, and local
distribution entities.\247\ Rather, the Commission encourages each
project sponsor to propose measures to mitigate the impacts of
reasonably foreseeable
[[Page 14120]]
GHG emissions associated with its proposed project, and will consider
such mitigation proposals in assessing the extent of a project's
adverse impacts.\248\
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\247\ See generally Tex. Pipeline Ass'n v. FERC, 661 F.3d 258,
260 (5th Cir. 2011) (holding that the Commission lacked authority to
require ``major non-interstate pipelines'' to post certain flow
information).
\248\ As described supra in section III.A.2.b, the Commission
will consider GHG emission mitigation and reduction efforts taken by
non-jurisdictional entities, including downstream users, when
quantifying the reasonably foreseeable project GHG emissions.
However, the project sponsor's GHG mitigation plan should only
include its own proposed mitigation efforts.
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105. We note that the Supreme Court's ruling in Public Citizen does
not preclude the Commission from requiring project sponsors to mitigate
reasonably foreseeable upstream or downstream emissions. As discussed
previously,\249\ the Commission may consider downstream GHG emissions
under Public Citizen, which states that ``NEPA requires `a reasonably
close causal relationship' between [an] environmental effect and the
alleged cause,'' analogous to the ``familiar doctrine of proximate
cause from tort law'' and does not require an agency to gather or
consider information regarding environmental harms if it lacks
authority to act on that information.\250\ As directed by Public
Citizen, decisionmakers should ``look to the underlying policies or
legislative intent in order to draw a manageable line between those
causal changes that may make an actor responsible for an effect and
those that do not.'' \251\ Here, the NGA ``broadly instruct[s]'' the
Commission to consider ``the public convenience and necessity'' when
evaluating proposed interstate pipeline applications, balancing public
benefits against adverse effects, including adverse environmental
effects,\252\ and we have noted that the Commission has consistently
exercised its broad conditioning authority under the NGA to attach
environmental conditions that mitigate the adverse environmental
impacts of a proposed project.\253\ NEPA requires an agency to consider
the environmental impacts of its actions, including steps that could be
taken to mitigate adverse environmental consequences,\254\ although it
does not require a federal agency to take action to mitigate those
adverse effects.\255\ As CEQ recognizes, an agency may, however,
require mitigation of impacts under its authority as a condition of its
permitting or approval.\256\ Thus, as the D.C. Circuit held in Sabal
Trail, the Commission can deny a pipeline certificate on the ground
that the pipeline would be too harmful to the environment, because the
agency is the ``legally relevant cause'' of the direct and reasonably
foreseeable environmental effects of the pipelines it approves.\257\
Accordingly, the Commission may consider the end use of gas and the
impact of natural gas combustion on air pollution as a factor in
assessing the public interest.\258\ However, as detailed below, the
Commission's priority is for project sponsors to mitigate, to the
greatest extent possible, a project's direct GHG emissions. The
Commission also encourages project sponsors to propose mitigation of
reasonably foreseeable indirect emissions, and will take such proposals
into account in assessing the extent of a project's adverse impacts.
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\249\ See supra section III.A.1.b.
\250\ Pub. Citizen, 541 U.S. at 767, 770 (quoting Metro. Edison
Co., 460 U.S. at 774); see Sabal Trail, 867 F.3d at 1372.
\251\ Pub. Citizen, 541 U.S. at 767 (quoting Metro. Edison Co.,
460 U.S. at 774 n.7).
\252\ Sabal Trail, 867 F.3d at 1373 (citing Minisink Residents
for Envtl. Pres. & Safety v. FERC, 762 F.3d 97, 101-02 (D.C. Cir.
2014); Myersville Citizens for a Rural Cmty. v. FERC, 783 F.3d 1301,
1309 (D.C. Cir. 2015)).
\253\ See supra P 97.
\254\ Robertson v. Methow Valley Citizens Council, 490 U.S. at
351 (``To be sure, one important ingredient of an EIS is the
discussion of steps that can be taken to mitigate adverse
environmental consequences.'').
\255\ Id. at 352 (``There is a fundamental distinction, however,
between a requirement that mitigation be discussed in sufficient
detail to ensure that environmental consequences have been fairly
evaluated, on the one hand, and a substantive requirement that a
complete mitigation plan be actually formulated and adopted, on the
other.''); S. Fork Band Couns. of W. Shoshone of Nev. v. U.S. Dep't
of Interior, 588 F.3d at 727 (NEPA does not require that agencies
mitigate significant environmental harms).
\256\ Final Guidance for Federal Departments and Agencies on the
Appropriate Use of Mitigation and Monitoring and Clarifying the
Appropriate use of Mitigated Findings of No Significant Impact, 76
FR 3843, 3848.
\257\ Sabal Trail, 867 F.3d at 1373 (distinguishing Public
Citizen).
\258\ See supra P 80.
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3. Mitigation Measures
106. The Commission encourages the project sponsor to propose
measures to mitigate the direct GHG emissions of its proposed project
to the extent these emissions have a significant adverse environmental
impact.\259\ INGAA describes three possible levels of mitigation--to
zero, to a level of below significance, and to an amount to be
determined by use of the SCC--but dismisses each as unworkable,
improperly adopting broad policy judgements, and reliant on a one-sided
and imprecise methodology, respectively.\260\ The Commission plans to
evaluate proposed mitigation plans on a case-by-case basis and is not
mandating a standard level of mitigation. We also encourage project
sponsors to proposed measures to mitigate the reasonably foreseeable
upstream or downstream emissions associated with their projects.
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\259\ The Attorneys General of Massachusetts, Delaware,
Maryland, Michigan, Minnesota, New Jersey, Rhode Island, and the
District of Columbia (Attorneys General of Massachusetts et al.)
recommends that the Commission include reasonable, binding
mitigation measures that incorporate any applicable state or federal
regulations or permit conditions. Attorneys General of Massachusetts
et al. Technical Conference Comments at 6. The technical conference
commenters are made up of a slightly different group of state
attorneys general than those filing comments in 2018 or 2021. As
explained below, the Commission is only considering mitigation
measures that reduce emissions beyond those associated with
regulatory requirements in this policy statement.
\260\ INGAA Technical Conference Comments at 21-27; 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).
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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.
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\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.
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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
[[Page 14121]]
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.
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\263\ See supra section II.B.
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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:
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\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\
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\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\
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\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.
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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\
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\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).
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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
[[Page 14122]]
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\
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\272\ For more information, see EPA Green Power Partnership,
Offsets and RECs: What's the Difference (Feb. 2018), <a href="https://www.epa.gov/sites/default/files/2018-03/documents/gpp_guide_recs_offsets.pdf">https://www.epa.gov/sites/default/files/2018-03/documents/gpp_guide_recs_offsets.pdf</a>.
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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<INF>2</INF>) or CO<INF>2</INF>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.
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\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).
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ii. Mandatory Compliance Market Participation
117. The compliance market is a mandatory offset program regulated
by national, regional, or provincial law and mandates CO<INF>2</INF>
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<INF>2</INF> emissions at certain electric power generators. Each
region involved in RGGI has an established emissions budget (cap) and
each electric power generator holds allowances covering their GHG
emissions. If a generator is below its established cap, it may trade an
allowance to other entities \276\ that exceed their cap. RGGI has an
established emissions-based auction and trading system where allowances
are bought, sold, and traded.\277\ In addition to allowances, offsets
may be used for compliance purposes, which requires a third-party
certification of that offset for use. RGGI strictly regulates the
quantity and types of offsets. There are five pre-determined types of
RGGI offsets:
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\275\ RGGI includes: Connecticut, Delaware, Maine, Maryland,
Massachusetts, New Hampshire, New Jersey, New York, Rhode Island,
Vermont, and Virginia.
\276\ Any entity is eligible to participate in CO<INF>2</INF>
allowance auctions including, but not limited, to corporations,
individuals, non-profit corporations, environmental organizations,
brokers, and other interested parties. The Regional Greenhouse Gas
Initiative, CO2 Allowance Auctions, Frequently Asked Questions 1
(Apr. 6, 2021), <a href="https://www.rggi.org/sites/default/files/Uploads/Auction-Materials/54/FAQS_Apr_6_2021.pdf">https://www.rggi.org/sites/default/files/Uploads/Auction-Materials/54/FAQS_Apr_6_2021.pdf</a>.
\277\ 23.5 million CO<INF>2</INF> allowances (short tons) sold
at RGGI auction in March 2021 at clearing price of $7.60/allowance.
a. Landfill gas (methane) capture/burning;
b. sulfur hexafluoride capture/recycling;
c. afforestation (the establishment of a forest in an area where
there was no previous tree cover);
d. energy efficiency (end use); and
e. agricultural manure management operations (avoided
emissions).
119. In addition to RGGI, California participates in the Western
Climate Initiative with Quebec and Nova Scotia,\278\ covering
industrial production, electricity generation, residential, commercial,
and small industrial combustion, and transportation fuel combustion.
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\278\ 54.7 million CO<INF>2</INF> allowances (metric tons) sold
at settlement price of $17.8/allowance during a February 2021
auction.
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120. If an applicant proposes any method of market-based mitigation
of GHG emissions, such as those described in this section, we encourage
the applicant to inform the Commission of any state or regional
compliance goals or initiatives that may be relevant to our
consideration of such mitigation proposal.
iii. Voluntary Carbon Market Participation
121. If a project sponsor is not located in a state that
participates in a mandatory compliance market, the voluntary carbon
market offers an opportunity to mitigate project emissions. The
voluntary carbon market transacts with offsets, which are the
instrument representing the reduction, avoidance, or sequestration of
one metric ton of GHG.\279\ The voluntary market funds additional,
external projects that avoid or reduce GHG emissions.\280\ The
voluntary carbon market is open to project sponsors regardless of
location and is more flexible than compliance markets, although each
market has its own standards, registries, and project types. Offset
allowances are issued to project sponsors of qualifying CO<INF>2</INF>
emissions offset projects.
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\279\ EPA Green Power Partnership, supra note 272.
\280\ In 2019, 104 million metric tons of CO<INF>2</INF>e
offsets were sold and the price per metric ton CO<INF>2</INF>e was
$1.40 to $4.30, depending on type of project (renewable energy and
forestry/land use, respectively). S&P Global Platts, Voluntary
Carbon Market Grows 6% on Year in 2019: Ecosystem Marketplace (Sep.
22, 2020), <a href="https://www.spglobal.com/platts/en/market-insights/latest-news/coal/092220-voluntary-carbon-market-grows-6-on-year-in-2019-ecosystem-marketplace">https://www.spglobal.com/platts/en/market-insights/latest-news/coal/092220-voluntary-carbon-market-grows-6-on-year-in-2019-ecosystem-marketplace</a>.
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122. Typically, an independent third party qualifies offset
projects and establishes standards to verify offsets; however, not all
offsets available in the voluntary market are certified by a third
party. In order to ensure the additionality and permanence of offsets,
the use of unverified offsets is discouraged. If a project sponsor
proposes to mitigate project emissions through participation in a
voluntary carbon market, the sponsor is encouraged to seek Commission
approval of the third party that would verify the offsets prior to
participation. Examples of existing, acceptable third-party certifiers
include:
a. Climate Action Reserve; \281\
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\281\ Typical offset projects include ozone depleting substances
destruction, landfill gas capture/combustion, livestock gas capture/
combustion, improved forest management, avoided grassland
conversion, and improved forest management, among others. For more
information, see generally <a href="https://www.climateactionreserve.org/">https://www.climateactionreserve.org/</a>.
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b. Verified Carbon Standard; \282\ and
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\282\ Typical offset projects include renewable energy, forest
and wetland conservation and restoration, transport efficiency
improvement, nitrous oxide abatement, clean cookstoves, methane
capture and use/combustion, and waste heat recovery. For more
information, see generally <a href="https://verra.org/">https://verra.org/</a>.
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c. American Carbon Registry.\283\
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\283\ Typical offset projects include ozone depleting substances
destruction, industrial process emissions, fuel switching, livestock
waste management, transport fleet efficiency, landfill gas capture
and combustion, wetland restoration, forest management, and coal
mine methane capture. For more information, see generally <a href="https://americancarbonregistry.org/">https://americancarbonregistry.org/</a>.
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123. Some commenters support allowing project sponsors to purchase
emissions offsets while others oppose it as a mitigation method. For
example, Policy Integrity recommends that the
[[Page 14123]]
Commission require certificate holders to purchase emission offsets
from a third party.\284\ Policy Integrity states that carbon offsets
are: (1) Consistent with compensatory mitigation requirements employed
by other federal agencies, such as the Bureau of Land Management, U.S.
Fish and Wildlife Service, and EPA; and (2) included and supported in
CEQ's NEPA regulations and guidance.\285\ Policy Integrity also
recommends that the Commission develop a carbon offset program as
opposed to relying on third-party programs; \286\ however, the
Commission lacks statutory authority to create such a program and
believes that the existing programs and certifiers mentioned above are
sufficient.
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\284\ Policy Integrity 2021 Comments at 14-15, 19.
\285\ Policy Integrity 2021 Comments at 23-26 (citing 40 CFR
1508.1(s)(5)).
\286\ Policy Integrity 2021 Comments at 20.
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124. Conversely, some commenters oppose the Commission requiring
project sponsors to purchase offsets from third parties because it is
difficult to ensure that carbon offsets have the necessary traits of
additionality (the reduction would not have happened but for the
purchased offset), permanence (the reduction persists for the entire
certification period of the offset), absence of leakage (the offset
does not trigger some other activity elsewhere that adds GHG
emissions), and rigorous third-party verification.\287\ INGAA further
comments that it would be difficult or impossible for the Commission to
choose an appropriate level of offsetting because of the variability in
emissions over the life of a project and the risk of over-counting for
a given quantity of gas that might move over multiple jurisdictional
transportation projects, and that not enough high-qualify offsets are
available.\288\ Commissioner Kelliher cautions that the Commission
would have to verify offsets given concerns about fraud and
environmental and accounting integrity.\289\ As previously stated, the
Commission is not requiring project sponsors to purchase offsets or
mandating a certain level of offsetting, and while the Commission
acknowledges the challenges with third-party offsets, we believe the
certifiers mentioned above will sufficiently account for them.
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\287\ Enbridge Pre-Conference Comments at 7-8; INGAA 2021
Comments at 79-82.
\288\ INGAA Technical Conference Comments at 34-36; INGAA 2021
Comments at 79-82; see also Enbridge Pre-Conference Comments at 8-9;
Enbridge Technical Conference Comments at 46-47.
\289\ Hon. Joseph T. Kelliher Technical Conference Comments at
7; see also id. (asserting that this process would be complicated
because credits could originate outside the U.S. and the Commission
has no verification expertise).
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b. Physical Mitigation
125. In addition to purchasing RECs or emissions offsets, project
sponsors could also propose to mitigate and/or offset GHG emissions
through the use of physical, on- or off-site mitigation measures.
Physical mitigation measures could include smaller-scale efforts
including reducing a project's fugitive methane emissions or
incorporating renewable energy or other energy efficient technologies
to reduce a project's GHG emissions from compressor stations, or
larger-scale undertakings such as carbon capture and storage, or direct
air CO<INF>2</INF> capture. Project sponsors could also propose
environmentally based measures, such as planting trees along the right-
of-way or in other locations to offset carbon emissions or restoring
wetlands to provide additional carbon storage; however, the scale
needed for such measures to meaningfully mitigate GHG emissions may
render them impractical. In addition, project sponsors could propose to
reduce GHG emissions from their existing facilities, including those
with no direct connection to the proposed project, as mitigation for
project-related emissions.
126. Commenters detail a host of mitigation measures they are
currently undertaking or propose to implement to reduce direct project
emissions, such as: Installing vent gas recovery systems and optimizing
operations to reduce venting and blowdowns, replacing cast iron/
unprotected steel pipes with polyethylene or protected steel pipes to
minimize leaks, employing a variety of technologies and methods to
identify and reduce leaks, and replacing natural gas-fired horsepower
at compressor stations.\290\ Other commenters echo some of those
suggestions \291\ and recommend operational limits on construction
equipment, such as limited idle time when engines are not in use.\292\
Other commenters criticize any mitigation measures, especially carbon
capture and sequestration and offsets, and recommend that the
Commission achieve ``real zero'' emissions that accounts for air and
water pollution and focuses on environmental justice communities and
workers impacted by the negative externalities associated with project
operation and jobs that are being phased out.\293\ Some commenters
assert that direct emissions are already substantially mitigated
pursuant to the regulatory authority exercised by other agencies.\294\
With regard to methane leaks, Dr. Anna Scott explains that its
independent certification and measurement program verifies that a
company's operations meet regulatory standards and incentivize
companies to go beyond the standards by using an engineering-based
review process that assesses development through to operations, as well
as continuous monitoring of emissions along the supply chain.\295\ On a
policy level, Gary
[[Page 14124]]
Choquette of Pipeline Research Council International (PRCI) argues for
a centralized funding mechanism for pipeline research to establish gas
quality requirements with the aim of maximizing supply and reducing
emissions and notes that PRCI has developed a tool that provides a
method for prioritizing alternatives to reduce emissions based on
effectiveness and associated capital and operating costs.\296\
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\290\ E.g., AGA Technical Conference Comments at 28-30; API
Technical Conference Comments at 6-8; Boardwalk Technical Conference
Comments at 5-6; Con Edison Technical Conference Comments at 7-10
(detailing other efforts reduce emissions using renewable natural
gas, certified natural gas, and hydrogen); Enbridge Pre-Conference
Comments at 5; Enbridge Technical Conference Comments at 13-14, 39-
41; INGAA Technical Conference Comments at 28-30 (citing its 2021
Climate Report); Magnolia LNG LLC Technical Conference Comments at 2
(describing its proprietary technology to reduce emissions during
the liquefaction process); Scott A. Hallam Technical Conference
Statement at 2 (Scott A. Hallam, Senior Vice President of
Transmission and Gulf of Mexico at Williams, was a panelist at the
GHG Technical Conference on Panel 1.); Stephen Mayfield Technical
Conference Statement at 1-2 (Stephen Mayfield, AGM of Gas Operations
at City of Tallahassee, was a panelist at the GHG Technical
Conference on Panel 3.); Texas LNG Brownsville LLC Technical
Conference Comments at 6; William F. Donahue Technical Conference
Statement at 3 (William F. Donahue, Manager of Natural Gas Resources
at Puget Sound Energy, was a panelist at the GHG Technical
Conference on Panel 2.); INGAA 2021 Comments at 79-82. Some
commenters note, however, that use of electric compressors may
increase indirect emissions depending on the generation mix and
existing infrastructure or cite concerns about the impact to the
reliability of gas service during power outages. E.g., American
Forest Technical Conference Comments at 13; Enbridge Pre-Conference
Comments at 5-6; Enbridge Technical Conference Comments at 41;
Kinder Morgan Technical Conference Comments at 22-23.
\291\ Delaware Riverkeeper 2021 Comments at 66; Kirk Frost 2021
Comments at 11.
\292\ Delaware Riverkeeper 2021 Comments at 66.
\293\ Rachel Dawn Davis, the Public Policy and Justice Organizer
at Waterspirit, was a panelist at the GHG Technical Conference on
Panel 3. Rachel Dawn Davis Technical Conference Statement at 1;
Waterspirit Technical Conference Comments at 1-2; see also Technical
Conference Transcript at 106-107 (transcribing remarks made by Dr.
Nicky Sheats, Director of the Center for Urban Environment at the
John S. Watson Institute for Public Policy and panelist on Panel 2).
\294\ E.g., TC Energy Technical Conference Comments at 20.
\295\ Dr. Anna Scott, Co-Founder and Chief Science Officer of
Project Canary, was a panelist at the GHG Technical Conference on
Panel 2. Dr. Anna Scott Technical Conference Statement at 1-2, 5
(mentioning key engineering components such as operational venting
or flaring, electrification of facilities and equipment, low bleed
and/or zero bleed process controls, leak detection and repair
programs, produced water treatment and reuse, and infrastructure and
facility efficiency investments and describing how the company uses
on-site sensors and algorithm technology to provide continuous
monitoring). Along with pursuing carbon capture and storage
solutions, Ivan Van der Walt, Chief Operating Officer at NextDecade
Corporation and a panelist at the GHG Technical Conference on Panel
2, describes the joint pilot project NextDecade has formed with
Project Canary for measuring and certifying the GHG intensity of LNG
sold from the Rio Grande LNG Project export facility. Ivan Van der
Walt Technical Conference Statement at 2-3.
\296\ Gary Choquette, Executive Director of Research and IT at
PRCI, was a panelist at the GHG Technical Conference on Panel 2.
Gary Choquette Technical Conference Statement at 3-4.
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127. Commenters also recommend that the Commission consider a
project sponsor's participation in programs that help shippers
voluntarily reduce emissions and other voluntary emissions reductions
programs when evaluating mitigation measures, such as the ONE Future
Coalition, Oil and Gas Climate Initiative, Climate and Clean Air
Coalition Oil and Gas Methane Partnership, EPA Natural Gas STAR Program
and Natural Gas STAR Methane Challenge Program, Methane Guiding
Principles, the Natural Gas Sustainability Initiative, and The
Environmental Partnership.\297\ The Commission encourages project
sponsors to detail their participation in such programs and any other
voluntary measures as part of their mitigation plan for the Commission
to consider as part of its public interest determination.
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\297\ See, e.g., AGA Technical Conference Comments at 17-20; API
Technical Conference Comments at 7-8; Boardwalk Technical Conference
Comments at 5-6; NGSA Technical Conference Comments at 5; Scott A.
Hallam Technical Conference Statement at 2-3; Stephen Mayfield
Technical Conference Statement at 1; William F. Donahue Technical
Conference Statement at 3-4; BHE Pipeline Group 2021 Comments at 12-
14; Cheniere Energy Inc. 2021 Comments at 17.
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c. Cost Recovery
128. Commenters request that the Commission allow full cost
recovery for any GHG mitigation measures through either the section 7
process or a general section 4 rate case for capitalized mitigation
costs but caution the Commission to ensure that mitigation efforts are
verified and the consumer's interest in low prices are balanced with a
project sponsor's right to recover costs and earn a fair rate of return
under the NGA.\298\ Alternatively, for periodic purchases of market-
based mitigation measures specifically, commenters state that pipelines
could propose a tracker through a limited section 4 filing.\299\
Conversely, other commenters oppose passing mitigation costs along to
shippers, especially if it would increase rates for end-users,
particularly low-income communities, who may not directly reap any
local environmental benefits.\300\ In the event mitigation costs are
passed to shippers, American Forest supports establishing a baseline
from which to judge emissions reductions and supports having an
independent entity monitor and measure those reductions.\301\ The
Commission has previously considered and approved a proposal by a
pipeline proponent to recover the costs of purchasing carbon offsets.
In 2010, Ruby Pipeline, L.L.C., proposed to voluntarily purchase GHG
offsets for the direct emissions associated with its compressor units
(approximately 523,000 metric tons of GHG per year).\302\ Going
forward, project sponsors wishing to purchase offsets or proposing
other measures to mitigate their project's GHG emissions may propose to
recover the costs of these measures through their proposed rates.
Applicants are encouraged to submit detailed cost estimates of GHG
mitigation in their application and to clearly state how they propose
to recover those costs. Pipelines may seek to recover GHG emissions
mitigation costs through their rates, similarly to how they seek to
recover other costs associated with constructing and operating a
project, such as the cost of other construction mitigation requirements
or the cost of fuel. Additionally, the Commission's process for section
7 and section 4 rate cases is designed to protect shippers from unjust
or unreasonable rates and will continue to do so with respect to the
recovery of costs for mitigation measures.
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\298\ Boardwalk Technical Conference Comments at 3; Enbridge
Technical Conference Comments at 15, 49; INGAA Technical Conference
Comments at 42-45; TC Energy Technical Conference Comments at 6.
\299\ Enbridge Technical Conference Comments at 15, 49; INGAA
Technical Conference Comments at 45 (noting that the Commission
should be clear that ``recovery of costs related to an ongoing
obligation to purchase market-based mitigation is akin to a fuel
tracker and would not be subject to the modernization cost recovery
tracker policy or the Commission's policy against cost recovery
trackers for regulatory compliance costs,'' and incremental
operating costs to reduce GHG emissions should also be recoverable
through a tracker); see also Hon. Joseph T. Kelliher Technical
Conference Comments at 7 (suggesting that, while burdensome to
stakeholders, the Commission could adopt a true-up mechanism
requiring project sponsors to deposit offsets, which would later be
compared to actual emissions).
\300\ American Forest Technical Conference Comments at 15-16;
APGA Technical Conference Comments at 6-8 (urging the Commission to
consider the effects of cost-recovery on end-users, particularly
low-income communities, who may not directly reap any local
environmental benefits); American Forest and Paper Association et
al. 2021 Comments at 26.
\301\ American Forest Technical Conference Comments at 14
(asserting that there is little transparency for customers with
respect to Lost and Unaccounted for Fuel Charges, which are
recoverable by shippers).
\302\ Ruby Pipeline, LLC, 131 FERC ] 61,007, at P 34 (2010).
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D. Application of Policy Statement
129. We will apply this interim policy statement to both pending
and new NGA section 3 and 7 applications.\303\ As noted above, doing so
will allow the Commission to evaluate and act on such applications
without undue delay. Applicants with pending applications will be given
the opportunity to supplement the record and explain how their
proposals are consistent with this policy statement, and stakeholders
will have an opportunity to respond to any such filings. A project
sponsor for any new natural gas infrastructure project is encouraged to
include the following in its NGA section 3 or 7 application:
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\303\ Unless required by law or regulation, the Commission will
not apply a presumptive significance threshold below 100,000 metric
tons of CO2e to applications filed prior to issuance of a final
policy statement. If the Commission adopts a new lower threshold in
a final policy statement, that threshold will only apply to
applications filed after issuance of that statement.
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<bullet> The project's projected utilization rate and supporting
in
[…truncated; see source link]Indexed from Federal Register on March 11, 2022.
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