Commissioner James Danly Statement
June 21, 2021
Docket No. CP20-455-000
Item C-1
I concur in part because I agree that the Commission should grant the Natural Gas Act (NGA) section 3[1] authorization requested by Freeport LNG Development, L.P., FLNG Liquefaction, LLC, FLNG Liquefaction 2, LLC, and FLNG Liquefaction 3, LLC (collectively, Freeport LNG). I dissent in part because the Commission applies its new “standard”—referred to (by some) as the “eyeball” test[2]—for determining the significance of a project’s emissions. As explained in detail in my dissent in Northern Natural Gas Company,[3] the Commission’s “eyeball” test and its application constitute a clear violation of the Administrative Procedure Act (APA). The APA affords great flexibility to agencies to carry out their assigned roles, but they must conduct their business logically, explain their choices, and base them on evidence.[4] The “eyeball” test meets none of these basic requirements.
Instead of establishing a framework (or, for that matter, even establishing an arbitrary but clear threshold) to assess significance, the Commission merely concludes that “[b]ased on this record of GHG emissions, we find that the project’s contribution to climate change would not be significant.”[5] No further analysis is offered. The Commission does not explain how it arrived at its finding. Nor can any explanation be discerned from the Commission’s recent issuances.[6]
I, for one, am not confident that the Commission will ever come up with the evidence and explanation necessary to support its “eyeball” test. In February 2021, the Commission issued a second Notice of Inquiry asking additional and modified questions regarding its policies for certificating interstate natural gas facilities, including “[i]s there any level of GHG emissions that would constitute a de minimis impact?”[7] As of June 16, 2021, an eLibrary search showed more than 150 comments filed; of those comments, “de minimis” appears in eleven of them, and none of those comments appear to support the majority’s de minimis threshold.[8] Moreover, multiple commenters asked that the Commission provide guidance on its new “standard.”[9]
Nor do I believe it likely that the Commission will be required by the courts to provide an explanation. Even if Freeport LNG requests rehearing on this issue, the Commission will likely employ one of its new maneuvers—finding that Freeport LNG is not aggrieved and dismiss its rehearing request without addressing the merits.[10] And, of course, Freeport LNG has no incentive to petition for judicial review: they have their certificate and would be unlikely to jeopardize it in order to vindicate a point of legality. Again, with this issuance, stakeholders are simply left to puzzle out our thinking, knowing that, ultimately, these decisions are based on no more than the majority’s caprice.
Nevertheless, even if the framework by which the Commission has assessed significance cannot be deduced from our order, a few other regulatory goalposts (potentially moving) can be discerned from the Commission’s recent issuances. First, the Commission appears to apply its “eyeball” test to projects that only replace abandoned capacity or provide no natural gas transportation service.[11] Second, it appears that Commission staff have been directed to automatically prepare environmental impact statements (EIS) for projects that add capacity, including those already pending, even when they have a completed and issued Environmental Assessment (EA) that found the proposed project had no significant impact.[12] Third, Commission staff appears to have potentially been directed to prepare an EIS for prior notice activities conducted under a pipeline’s blanket authority.[13] And fourth, other than procedural requirements, the difference between our EAs and the forthcoming EISs seem to be confined to the format and title; the analysis appears to remain the same.[14]
If, as I fear, the pending projects’ EAs are being revisited, as in the Iroquois Gas Transmission System, L.P. proceeding in Docket No. CP20-48-000, for no purpose other than to be repackaged and reissued as EISs while maintaining the same analysis, then all that can be said about this maneuver is that it will unnecessarily delay the Commission’s consideration of these projects, increase the already dire regulatory uncertainty faced by jurisdictional entities, and will offer no benefit whatever to the Commission’s decision making. Given that, it is hard not to take a cynical view of the motives animating these issuances.[15]
In sum, significant changes to the Commission’s certificate program, (many imposed unilaterally) are underway—all while the Commission considers potential reform.[16]
For these reasons, I respectfully concur in part and dissent in part.
[1] 15 U.S.C. § 717b.
[2] Catherine Morehouse, Glick, Danly spar over gas pipeline reviews as FERC considers project’s climate impacts for first time, Utility Dive (Mar. 19, 2021), https://www.utilitydive.com/news/glick-danly-spar-over-gas-pipeline-reviews-as-ferc-considers-projects-cli/597016/ (“‘We essentially used the eyeball test,’ he said, adding that based on that analysis, ‘it didn’t seem significant in terms of the impact of those emissions on climate change.’”).
[3] N. Nat. Gas Co., 174 FERC ¶ 61,189 (2021) (Danly, Comm’r, concurring in part and dissenting in part).
[4] See Elec. Consumers Res. Council v. FERC, 747 F.2d 1511, 1515 (D.C. Cir. 1984) (finding that “the record lack[ed] substantial evidence to support the . . . methodology chosen, and . . . the Commission’s stated reasons for its approval [were] almost wholly conclusory, largely short-sighted and patently unpersuasive”).
[5] Freeport LNG Dev., L.P., 175 FERC ¶ 61,237, at P 23 (2021). And to the extent to which the Commission’s analysis is informed by the emissions from the helium plant, I question the wisdom of those figures’ inclusion. It is unclear to me from the record before us that the helium plant, as a downstream consumer of the byproducts of boil-off-gas, meets the legal proximate cause standard articulated in Department of Transportation v. Public Citizen, 541 U.S. 752, 767 (2004).
[6] See Appendix1 .
[7] Certification of New Interstate Nat. Gas Facilities, 174 FERC ¶ 61,125, at P 17 (2021).
[8] See, e.g., Public Interest Organizations May 26, 2021 Comments in Docket No. PL18-1-000 at 54 (Accession No. 20210526-5218) (“The Commission cannot label any GHG emissions de minimis until it first conducts a cumulative and programmatic analysis of its program of permitting fossil fuel infrastructure.”).
[9] See, e.g., BHE Pipeline Group May 26, 2021 Comments in Docket No. PL18-1-000 at 9-10 (Accession No. 20210526-5238) (“BHE Pipeline Group strongly encourages the Commission to apply an analysis that is not overly burdensome and is clearly defined, realistically achievable, and predictable.”); National Fuel Gas Supply Corporation May 26, 2021 Comments in Docket No. PL18-1-000 at 16 (Accession No. 20210526-5223) (“Additionally, if FERC continues to evaluate GHG emissions associated with a proposed pipeline project, it must establish clear standards so that market participants and all stakeholder groups will have an appropriate understanding of what emissions information they will need to provide in order to allow FERC to properly evaluate the certificate application.”); Driftwood Pipeline LLC May 26, 2021 Comments in Docket No. PL18-1-000 at 3 (Accession No. 20210526-5254) (“Without a clear benchmark quantifying the amount of GHG emissions, or percent increase in GHG emissions, the Commission will consider to adversely affect the human environment, such that applicants can design their projects in a manner consistent with these limitations, project proponents will be left to guess at the Commission’s requirements.”).
[10] See, e.g., Algonquin Gas Transmission, LLC, 175 FERC ¶ 61,150 (2021) (finding parties not aggrieved and dismissing rehearing requests without addressing arguments that the Commission lacks the authority to reopen a final, non-appealable certificate order).
[11] See Freeport LNG, 175 FERC ¶ 61,237 (project involving no jurisdictional service); N. Nat. Gas Co., 175 FERC ¶ 61,238 (2021) (constructing pipe to replace abandoned pipe); N. Nat. Gas Co., 174 FERC ¶ 61,189 (same).
[12] See Commission Staff Notice in Tennessee Gas Pipeline Company, L.L.C. Docket No. CP20-493-000 (Accession No. 20210527-3054) (announcing schedule for EIS for proposed project adding capacity); Commission Staff Notice in North Baja Pipeline, LLC Docket No. CP20-27-000 (Accession No. 20210527-3052) (same); Commission Staff Notice in Columbia Gulf Transmission, LLC Docket No. CP20-527-000 (Accession No. 20210527-3049) (same); Commission Staff Notice in Iroquois Gas Transmission System, L.P. Docket No. CP20-48-000 (Accession No. 20210527-3047) (same).
[13] See Commission Staff Notice in Adelphia Gateway, LLC Docket No. CP21-14-000 (Accession No. 20210527-3046) (announcing schedule for EIS for project proposed under blanket certificate to add an electric motor-driven compressor unit at its Marcus Hook Compressor Station and to increase Adelphia Gateway, LLC’s certificated capacity by 16,500 dekatherms per day). I note that the EA for this project disclosed that the proposed project’s construction could emit a total of 2,827 metric tons of carbon dioxide equivalent (CO2e), while its operation could emit 369 metric tons of CO2e annually. See Environmental Assessment in Adelphia Gateway, LLC Docket No. CP21-14-000 at 11-12 (Accession No. 20210209-3004). The construction of the project could potentially increase CO2e emissions based on the 2019 national levels by 0.000049%; in subsequent years, the project operations could potentially increase emissions by 0.0000064%. It should be recognized these numbers are significantly lower than those in the Northern Natural Gas Company case approved by the Commission today. See N. Nat. Gas Co., 175 FERC ¶ 61,238 at P 24. The downstream end use of the gas transported by the incremental capacity is unknown. See Adelphia Gateway, LLC, Response to Data Request, Docket No. CP21-14-000, at 2 (filed Feb. 26, 2021) (Accession No. 20210226-5383) (“Adelphia is not aware of the ultimate end use of gas transported pursuant to the Agreement with South Jersey.”). Under the Council on Environmental Quality’s current regulations,
[a] ‘but for’ causal relationship is insufficient to make an agency responsible for a particular effect under NEPA. Effects should generally not be considered if they are remote in time, geographically remote, or the product of a lengthy causal chain. Effects do not include those effects that the agency has no ability to prevent due to its limited statutory authority or would occur regardless of the proposed action.
40 C.F.R. § 1508.1(g)(2) (2020).
[14] See Draft EIS in Iroquois Gas Transmission System, L.P. Docket No. CP20-48-000 (Accession No. 20210611-3022) (reiterating information in the September 30, 2020 EA, disclosing downstream emissions for informational purposes, continuing to conclude that no determination can be made regarding the significance of climate change, and responding to comments on the EA). Empty formalism is contrary to NEPA’s regulatory scheme. See Pub. Citizen, 541 U.S. at 767 (“[I]nherent in NEPA and its implementing regulations is a ‘rule of reason,’ which ensures that agencies determine whether and to what extent to prepare an EIS based on the usefulness of any new potential information to the decisionmaking process. Where the preparation of an EIS would serve ‘no purpose’ in light of NEPA’s regulatory scheme as a whole, no rule of reason worthy of that title would require an agency to prepare an EIS.”) (internal citations omitted) (emphasis added).
[15] To the extent to which my colleagues may wish to justify these choices by appeal to some vague concern regarding the ‘legal risk’ posed to these certificates were they to issue with an EA instead of an EIS, that argument can safely be put to rest. “Preparation of an EIS is mandated where uncertainty may be resolved by further collection of data.” Nat’l Parks & Conservation Ass’n v. Babbitt, 241 F.3d 722, 732 (9th Cir. 2001) (citation omitted) (emphasis added). The draft EIS issued in the Iroquois Gas Transmission System, L.P. proceeding, for example, demonstrates that uncertainty regarding the significance of the project’s emissions cannot be resolved by further collection of data. See supra note 14.
[16] But see Chairman Glick, May 21, 2021 Letter to Senator Manchin, Docket No. PL18-1-000 (filed May 24, 2020) (Accession No. 20210524-4017) (“I agree that the Commission should not delay action on these Certificates during the pendency of our ongoing inquiry into potential reforms to the Commission’s Natural Gas Certificate Policy Statement and, in fact, we are continuing to process these applications.”).
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Appendix
Case Name
Docket No.
Project Type
Direct Emissions from Operation
(metric tons per year (tpy))
Upper Bound Downstream Emissions
(metric tpy)
National Comparison[1]
State Comparison[2]
“Eyeball” Test
Northern Natural Gas Company
CP20-487
Replacement
351
0
0.000006%[3]
0.000078% in Nebraska
0.0002% in
South Dakota
Yes
Tuscarora Gas Transmission Company
CP20-486
Additional Capacity for LDC
7,553
289,700
0.0052%
0.83% and 1.08% of Nevada’s 2025 and 2030 GHG inventory goals, respectively
No
Northern Natural Gas Company
CP20-503
Additional Capacity for LDC
42,814
882,430
0.016%
The emissions from the project would represent 1.3% and 4.5% of Minnesota’s 2025 and 2050 GHG inventory goals, respectively
No
WBI Energy Transmission, Inc.
CP20-52
Additional Capacity for Producer
85,666
4.83 million
0.085%
8.3% in North Dakota
No
Enable Gas Transmission, LLC
Enable Gulf Run Transmission, LLC
CP20-68
CP20-70
Additional Capacity for Export and Unknown Use
1,808
10.622 million
0.18%
7.0% and 8.6 % of Louisiana’s 2025 and 2030 GHG inventory goals, respectively
No
Freeport LNG
CP20-455
Non-jurisdictional service
439.9[4]
0
0.000013%
0.00011% in Texas
Yes
Northern Natural
Gas Company
CP20-504
Replacement
3,533.6
0
0.000061%
0.0043% in Iowa
Yes
[1] For national and state comparison, the Commission determines the increase by considering both the project’s direct emissions from operation and the emissions from downstream consumption activities.
[2] For the state comparison, the Commission either determines the increase in emissions as compared to a state’s emission goals when available or determines an increase in existing state emissions.
[3] The comparison for Docket No. CP20-487 is based on the national levels in 2018. The other comparisons in this chart are based on the national levels in 2019.
[4] The Commission’s order in Docket No. CP20-455 states the estimated “maximum potential GHG emissions from operation of the project to be 329.3 metric tons per year of carbon dioxide equivalent (CO2e) for the non-jurisdictional helium plant and 439.9 metric tons per year of CO2e from fugitive emissions from the project piping.” Freeport LNG Dev., L.P., 175 FERC ¶ 61,237, at P 23 (2021). The national and state comparisons regarding the potential increase in emissions from the proposed project include the estimated emissions from the non-jurisdictional helium plant.