United States Court of Appeals

FOR THE DISTRICT OF COLUMBIA CIRCUIT

Argued January 19, 2022 Decided June 28, 2022

No. 20-1427

SIERRA CLUB, ET AL.,

PETITIONERS

v.

FEDERAL ENERGY REGULATORY COMMISSION,

RESPONDENT

MOUNTAIN VALLEY PIPELINE, LLC AND PUBLIC SERVICE 

COMPANY OF NORTH CAROLINA, D/B/A DOMINION ENERGY 

NORTH CAROLINA,

INTERVENORS

On Petition for Review of Orders of the

Federal Energy Regulatory Commission

Benjamin A. Luckett argued the cause for petitioners. With 

him on the briefs was Elizabeth F. Benson.

Matthew W.S. Estes, Attorney, Federal Energy Regulatory 

Commission, argued the cause for respondent. On the brief 

were Matthew R. Christiansen, General Counsel, Robert H.

Solomon, Solicitor, and Anand R. Viswanathan, Attorney.
2

Jeremy C. Marwell argued the cause for respondentintervenors Mountain Valley Pipeline, LLC and Public Service 

Company of North Carolina, Inc. With him on the brief were 

Matthew Eggerding, Matthew X. Etchemendy, James T. 

Dawson, Charlotte Taylor, Stephen Petrany, and James Olson.

Before: SRINIVASAN, Chief Judge, WILKINS and WALKER, 

Circuit Judges.

Opinion for the Court filed by Circuit Judge WILKINS.

WILKINS, Circuit Judge. Petitioners, all environmental

organizations, seek to vacate the Federal Energy and 

Regulatory Commission’s (“FERC” or the “Commission”)

order giving the green light to Mountain Valley, LLC to 

construct a new pipeline. That pipeline, the “Southgate 

Project,” would extend Mountain Valley’s Mainline System 

Project, connecting its terminus in Virginia to facilities in 

North Carolina. Its “newness,” as an extension of the nonoperational Mainline System Project, is one of the prime

subjects of dispute. Petitioners also request that we vacate the 

Commission’s denial of rehearing.

Petitioners challenge the Commission’s Certificate Order 

and its denial of rehearing as arbitrary and capricious on two 

bases: the approved return on equity rate and the adequacy of 

the Commission’s Environmental Impact Statement. Because 

the Commission’s decisions on both scores were reasonable 

and supported by substantial evidence, we deny the petition for 

review.

I.

The Natural Gas Act, 52 Stat. 821 (1938) (codified as 

amended at 15 U.S.C. §§ 717–717z) empowers the 
3

Commission to regulate the interstate transportation and sale of 

natural gas. Under Section 7 of the Act, a natural gas company 

cannot construct gas transportation facilities or extend its 

currently operational facilities without first obtaining a 

certificate of public convenience and necessity from the 

Commission. 15 U.S.C. § 717f(c)(1)(A). The Commission 

will issue a certificate if it finds that the service “is or will be 

required by the present or future public convenience and 

necessity.” Id. § 717f(e). The applicant must also be “able and 

willing properly to do the acts and to perform the service 

proposed and to conform to” the Act’s provisions as well as the 

Commission’s rules and regulations. Id.

The Commission will approve a pipeline’s proposed rate 

of sale as long as it is “just and reasonable.” Id. § 717c(a). If, 

however, the company is proposing a newly certificated 

service, the Commission will apply the less exacting “public 

interest” standard, under Section 7, to set the initial rate a 

pipeline can charge. Missouri Pub. Serv. Comm’n v. FERC, 

337 F.3d 1066, 1068 (D.C. Cir. 2003). Such a rate “hold[s] the 

line” until the Commission can engage in more extensive 

ratemaking proceedings under Sections 4 and 5 of the Act

down the road. Gulf South Pipeline Co. v. FERC, 955 F.3d 

1001, 1005 (D.C. Cir. 2020) (quoting Atl. Ref. Co. v. Pub. Serv. 

Comm’n of State of NY, 360 U.S. 378, 391–92 (1959)). 

Prior to approving a certificate on a proposed pipeline, the 

National Environmental Policy Act (“NEPA”) requires the 

Commission to evaluate the action’s environmental impacts. If 

the agency finds that the action is likely to significantly impact 

the environment, it must draft an environmental impact 

statement (“EIS”), detailing the action’s environmental 

impacts, potential mitigation methods, the action’s cumulative 

impacts, and reasonable alternatives to the action, including a 

no-action alternative. 40 C.F.R. §§ 1502.14, 1502.16,
4

1501.3(a)(3). NEPA requires agencies to “take a ‘hard look’ at 

the environmental consequences before taking a major action.” 

Baltimore Gas & Elec. Co., Inc., 462 U.S. 87, 97 (1983). 

II. 

The Mainline System Project has been plagued with issues 

since construction commenced in February 2018. Mountain 

Valley had planned for Mainline to consist of a new 303.5-

mile-long pipeline from Wetzel County, West Virginia to an 

interconnection with a compressor station in Pittsylvania 

County, Virginia. Following a series of adverse rulings from 

the Fourth Circuit, construction on the Mainline System has 

proceeded in fits and starts, culminating in a stop-work order 

in October 2019. As of June 2020, construction along the 

project’s right-of-way was 92% complete. 

Despite Mainline’s setbacks, on November 6, 2018, 

Mountain Valley filed an application with the Commission for 

the Southgate Project, which would connect the Mainline 

System’s terminus in Pittsylvania County, Virginia to 

Dominion Energy’s local facilities in Rockingham and 

Alamance Counties, North Carolina. Consisting of 75.1 miles 

of an underground natural gas transmission pipeline system, 

the pipeline would have the capacity to transport 375 million 

cubic feet of gas per day. Final EIS Executive Summary-1–2. 

Mountain Valley cites the project as necessary to meet the 

needs of Dominion Energy, its anchor shipper,1 which has 

pressed for additional natural gas transportation services in the

1 An anchor shipper is “one or a very few shippers with very large, 

significant volumes of natural gas that will financially support the 

initial design and cost of a project.” Regulations Governing the Open 

Season for Alaska Natural Gas Transportation Projects, 110 FERC 

¶ 61,095, ¶ 12 n.8 (2005).
5

region. Id. at Executive Summary-1. Petitioners jointly filed a 

protest in opposition to the project. 

On June 18, 2020, the Commission issued a certificate of 

public convenience and necessity, approving Mountain 

Valley’s application to build and operate the Southgate Project. 

See Mountain Valley Pipeline, LLC, 171 FERC ¶ 61,232 (2020)

(“Certificate Order”). Just over two months later, on August 

20, 2020, it denied Petitioners’ request for a rehearing. 

Mountain Valley Pipeline, LLC, 172 FERC ¶ 62,100 (2020)

(“Rehearing Order”). Particularly relevant to Petitioners’ 

claims, the Commission approved Mountain Valley’s 

requested initial rate of return on equity at 14 percent, rather 

than the typical 10.55 percent, because “[w]ithout cash flows 

from existing operations and a proven track record,” 

Southgate’s capital funding outlook more closely resembled 

that of a new pipeline than an extension of an operational one.

Certificate Order, ¶ 57. As for the project’s environmental 

impacts, the Commission noted that the EIS had fleshed out 

specific practices to mitigate erosion as well as sedimentation, 

and evaluated the cumulative impacts arising from its temporal 

and geographic proximity to the Mainline System. Id. ¶¶ 75, 

93, 141; Rehearing Order, ¶¶ 28–31. Commissioner (now 

Chairman) Glick partially dissented from the Commission’s 

Certificate Order, opposing the 14 percent return on equity rate 

and the failure to address the project’s greenhouse gas effects. 

Certificate Order, ¶¶ 1–23 (Glick, Comm’r, dissenting).

In October 2020, Petitioners filed a petition for our 

review.2 They urge us to vacate and remand the Commission’s 

2 The Public Service Company of North Carolina, Monacan Indian 

Nation, Sappony Tribe, and Mountain Valley Pipeline filed motions 

to intervene in the appeal, all of which were granted. See Clerk’s 

Order (Dec. 9, 2020). The Monacan Indian Nation and Sappony 

Tribe later moved to withdraw as intervenors in August 2021, after 
6

Certificate Order of June 18, 2020, as well as its order of 

August 20, 2020, denying Petitioners’ request for rehearing. 

III. 

Our jurisdiction over this appeal is secure under the 

Natural Gas Act. See 15 U.S.C. § 717r(b). The Act vests this 

Court with exclusive jurisdiction to review an objection to a 

Commission order so long as “such objection . . . [has] been 

urged before the Commission in the application for rehearing.” 

Id. Petitioners have satisfied this exhaustion requirement—

they present the same arguments on appeal as set forth in their 

rehearing request. See J.A. 763 (objecting to return on equity 

rate); J.A. 764 (adequacy of mitigation measures); J.A. 764–65 

(consideration of cumulative impacts). We are similarly 

assured that Petitioners have met their burden of establishing 

Article III standing.3 That being settled, we turn to the merits.

they reached an agreement with the Southgate Project’s developer. 

Their motion to withdraw was granted. See Clerk’s Order (Sept. 3, 

2021). 

3 To establish associational standing to sue on their members’ behalf, 

as Petitioners seek to do here, they must show: “(1) at least one of its 

members would have standing to sue in his or her own right; (2) the 

interests it seeks to protect are germane to the organization’s 

purpose; and (3) neither the claim asserted nor the relief requested 

requires the participation of individual members in the lawsuit.” 

Sierra Club v. FERC, 827 F.3d 59, 65 (D.C. Cir. 2016) (internal 

quotation marks and citations omitted). To meet the first prong, 

Petitioners must demonstrate that: “(1) at least one of its members 

has suffered an injury-in-fact that is concrete and particularized and 

actual or imminent, not conjectural or hypothetical; (2) the injury is 

fairly traceable to the challenged action; and (3) it is likely, as 

opposed to merely speculative, that the injury will be redressed by a 

favorable decision.” Id. (internal quotation marks and citations 

omitted). We are satisfied that Petitioners have met this burden here. 
7

IV. 

We will review both Petitioners’ Natural Gas Act and 

NEPA claims under the arbitrary and capricious standard. 

Marsh v. Oregon Nat. Res. Council, 490 U.S. 360, 378 (1989)

(Natural Gas Act); Minisink Residents for Envtl. Pres. & Safety 

v. FERC, 762 F.3d 97, 106 (D.C. Cir. 2014) (NEPA). In doing 

so, we ask whether “the Commission’s judgment is supported 

by substantial evidence and that the methodology used in 

arriving at that judgment is either consistent with past practice 

or adequately justified.” Emera Maine v. FERC, 854 F.3d 9, 

22 (D.C. Cir. 2017) (quoting Town of Norwood, Mass. v. 

FERC, 80 F.3d 526, 533 (D.C. Cir. 1996)). And while the 

Court cannot review an agency’s environmental analysis to 

“second-guess substantive decisions committed to the 

discretion of the agency,” it is clear that “simple, conclusory 

statements of no impact are not enough to fulfill an agency’s 

duty under NEPA.” Delaware Riverkeeper Network v. FERC, 

753 F.3d 1304, 1313 (D.C. Cir. 2014) (internal quotation marks 

and citation omitted). An arbitrary and capricious agency 

action in the NEPA context is one that “is not the product of 

reasoned decisionmaking.” Id. at 1313 (internal quotation 

marks and citation omitted).

A.

In setting “just and reasonable rates” for interstate 

pipelines under the Natural Gas Act, the Commission must 

Sierra Club and Appalachian Voices Member Margaret Whitehead 

attested that the project would traverse her property, thereby

permanently reducing her tree farm area and threatening a small lake. 

See Add. 74–75. A favorable decision by this Court, halting 

construction on the pipeline, would remedy this stated injury.
8

balance the interests of the pipeline and its ratepayers. COSTOF-SERVICE RATES MANUAL, FERC 1 (1999). To do so, the 

Commission typically conducts “cost-of-service ratemaking,” 

meaning that it sets a rate “based on a pipeline’s cost of 

providing service including an opportunity for the pipeline to 

earn a reasonable return on its investment.” Id. This rate is 

also referred to as the “recourse rate.”4 But the Commission 

also allows pipeline companies to charge “negotiated rates,” 

which permit a pipeline to forgo cost-of-service rates with an 

individual shipper. Alternatives to Traditional Cost-of-Service 

Ratemaking for Natural Gas Pipelines, 74 FERC ¶ 61,076, 

¶¶ 61,224–25 (1996). 

Zooming in further, the rate of return is made up of two 

principal components: return on equity and return on debt. 

Sierra Club v. FERC, 867 F.3d 1357, 1376 (D.C. Cir. 2017). 

The return on equity is “the cost to the utility of raising capital.” 

Emera Maine, 854 F.3d at 20 (internal quotation marks and 

citations omitted). Because equity investment is riskier than 

debt investment, equity investors usually earn a higher rate of 

return than debt investors. Sierra Club, 867 F.3d at 1376. If 

the pipeline is greatly indebted, its equity investors take on 

more risk and therefore will expect a higher rate of return, and 

vice versa. Id. at 1377. Typically, “greenfield” or new 

pipelines take on more risk and will accordingly be rewarded 

with higher rates of return. PennEast Pipeline Co., 162 FERC 

¶ 61,053, ¶ 59 (2018). 

4 The Commission defines a recourse rate as a “cost-of-service based 

rate for natural gas pipeline service that is on file in a pipeline’s tariff 

and is available to customers who do not negotiate a rate with the 

pipeline company.” Glossary, FERC (Aug. 31, 2020), 

https://www.ferc.gov/about/what-ferc/about/glossary#:~:text=class

%20of%20customers.-,Recourse%20Rate,rate%20with%20the%20

pipeline%20company.
9

Here, Mountain Valley proposed that the Commission 

treat Southgate as a separate rate zone from the Mainline 

System so that the project’s costs and risks are borne by 

Mountain Valley and Southgate customers alone, rather than 

its Mainline System customers. Certificate Order, ¶ 25. As a 

result, it suggested a capital structure of 50 percent debt and 50

percent equity, a proposed cost of debt of 6 percent, a return on 

equity of 14 percent, and a 5 percent depreciation rate based on 

a 20-year contract with Dominion. Id. ¶ 53. The Commission 

approved the proposal. Id. ¶ 54. While it acknowledged that 

14 percent is higher than the typical return on equity for 

expansion projects, the Commission nonetheless found it 

reasonable, given that the Mainline System was not yet 

operational, did not have an existing revenue base, and 

Mountain Valley had no proven track record. Id. ¶ 57. 

Typically, FERC’s policy for expansion projects is to “require 

a pipeline to use the [return on equity] approved in its last NGA 

section 4 rate proceeding, or, if the pipeline has not filed a rate 

case, the [return on equity] from the last litigated NGA section 

4 rate case.” Id. ¶ 22 (Glick, Comm’r, dissenting). Because 

Mountain Valley had not yet litigated a rate case, the 

Commission would have applied the return on equity rate 

authorized in El Paso Natural Gas Company, its most recent 

NGA case, of 10.55 percent. 145 FERC ¶ 61,040, ¶ 686 

(2013).

Petitioners challenge the 14 percent return on equity as 

inadequately supported and, by extension, arbitrary and 

capricious. In doing so, they fix their gaze on two of the 

Commission’s purported errors. 

First, they assert that the Commission did not consider 

current market conditions or support the authorized return on 

equity with empirical data. Rather than “closely scrutiniz[ing]” 
10

Mountain Valley’s requested rate, the Commission simply 

relied on previous rates for new market entrants to approve the 

14 percent return on equity here. Pet’rs’ Br. at 20–21. In their 

view, such a decision risks skewing incentives for building new 

and unnecessary pipelines. When setting an initial rate under 

Section 7, the Commission is not required, however, to set a 

return on equity rate based on market conditions and empirical 

data. It is true that “[a] rate of return may be reasonable at one 

time and become too high or too low by changes affecting 

opportunities for investment, the money market and business 

conditions generally.” Bluefield Waterworks & Imp. Co. v. 

Pub. Serv. Comm’n of West Virginia, 262 U.S. 679, 693 (1923). 

But the Natural Gas Act does not compel an explicit 

consideration of market conditions in all circumstances. See 

15 U.S.C. § 717c(a). Indeed, the Commission’s typical policy 

in Section 7 proceedings is to apply the rate determined in the 

last NGA section 4 proceeding. Petitioners do not challenge 

this policy, nor do they provide support for the claim that 

market conditions and empirical data must factor into the 

Commission’s calculus. Thus, their focus on these factors is

unavailing.

Petitioners’ fear that the return on equity presents a 

market-skewing incentive is similarly misplaced. The 

Commission explained that Mountain Valley’s precedent 

agreement for 80 percent of the project’s capacity indicated the 

need for the project. Precedent agreements are often—though 

not always—reliable indicators of market need for a pipeline 

project. See Appalachian Voices v. FERC, No. 17-1271, 2019

WL 847199, at *1 (D.C. Cir. Feb. 19, 2019) (per curiam); but 

see Envtl. Def. Fund v. FERC, 2 F.4th 953, 973 (D.C. Cir. 

2021). Here, the long-term agreement shows an actual need for 

the Project, not an attempt on Mountain Valley’s part to 

overbuild purely for profit. 
11

Second, Petitioners argue that the Commission erred in 

treating Mountain Valley as a new market entrant, in spite of 

its prior experience with the Mainline System Project. 

Petitioners rely heavily on Commissioner Glick’s dissent from 

the Certificate Order in support of this argument. 

Commissioner Glick characterized the 14 percent return on 

equity as a break from precedent for incremental expansion 

projects. Certificate Order, ¶ 4 & n.330 (Glick, Comm’r,

dissenting). In Cheyenne Connector, LLC, for example, the 

Commission rejected a pipeline company’s proposed return on 

equity of 13 percent because the project “has more in common 

with the incremental expansions constructed by existing 

pipelines than with greenfield pipeline projects.” 168 FERC 

¶ 61,180, ¶ 52 (2019). See also Gulfstream Natural Gas Sys., 

LLC, 170 FERC ¶ 61,199, ¶¶ 18–19 (2020) (rejecting a return 

on equity of 14 percent for existing pipeline’s expansion 

project); Cheniere Corpus Christi Pipeline, LP, 169 FERC 

¶ 61,135, ¶¶ 34–35 (2019) (same). Because the Commission 

already granted Mountain Valley a 14 percent return on equity 

as a new market entrant for Mainline, Commissioner Glick 

believed it should not receive such a favorable return on equity 

the second time around. Certificate Order, ¶ 22 (Glick, 

Comm’r, dissenting). Further, Commissioner Glick would

have treated Mountain Valley as an existing pipeline company

due to its executed binding service contracts with shippers. Id. 

Those contracts provide a level of revenue security that most 

greenfield projects do not enjoy. Id. 

The question of whether the Commission should have 

treated Mountain Valley and Southgate as a “new market 

entrant” and “greenfield pipeline,” respectively, depends on 

whether we take a formalist or functionalist approach. 

Formally, as Petitioners would have it, Southgate is an 

extension of a partially constructed pipeline, and this is not 

Mountain Valley’s first rodeo at the Commission. 
12

Functionally, as the Commission views it, Mountain Valley 

does not have the track record or revenue stream of existing 

pipeline operations and should be treated as new to the market. 

In these circumstances, the Commission’s functional approach

was reasonable.

In City of Oberlin, Ohio v. FERC, 937 F.3d 599 (D.C. Cir. 

2019), we set out a host of factors to consider in determining 

whether the Commission acted in the public interest in 

approving a particular return on equity. First, although a “bare 

citation to precedent” or reflexive use of a past rate will not 

suffice, invoking precedent to balance consumer and investor 

interests will aid the Commission’s case. Id. at 609 (quoting 

Sierra Club, 867 F.3d at 1378). Second, the Commission can 

support its approval of a rate by responding to specific 

objections in its Certificate Order. Id. And finally, it should 

explain the risks the proposed pipeline faces and why that 

justifies the return on equity. Id. What will doom the 

Commission’s approval of a return on equity is a “fail[ure] to 

consider an important aspect of the problem, offer[ing] an 

explanation for its decision that runs counter to the evidence 

before the agency, or [one that] is so implausible that it could 

not be ascribed to a difference in view or the product of agency 

expertise.” Id. at 610.

First, in looking to past precedent, the Commission will 

typically charge the rate set under the last Section 4 proceeding. 

But it has repeatedly approved higher rates for greenfield 

projects. See PennEast Pipeline Co., 162 FERC ¶ 58 

(approving a 14 percent return on equity for new market 

entrant, despite the fact that its system capacity was 90 percent

subscribed); Mountain Valley Pipeline, LLC, 161 FERC 

¶ 61,043, ¶ 84 (2017) (upholding 14 percent return on equity

with stipulation that Mountain Valley must shift its capital 

structure from 40 percent to 50 percent debt); Appalachian 
13

Voices, 2019 WL 847199, at *1 (upholding 14 percent return 

on equity for Mountain Valley’s Mainline System Project); 

Corpus Christi LNG, L.P. Cheniere Corpus Christi Pipeline 

Co., 111 FERC ¶ 61,081, ¶ 33 (2005) (approving 14 percent 

return on equity for a new pipeline with a 50-50 debt to equity 

ratio). 

The Commission’s decision in Rockies Express Pipeline 

LLC, 116 FERC ¶ 61,272 (2006) is particularly instructive. 

There, the Commission approved a 13 percent return on equity 

for an expansion project, linking up to a previously authorized, 

but not yet completely operational, greenfield pipeline. Id. 

¶¶ 4, 44. The higher rate was warranted, in the Commission’s 

view, given the attendant risks of a pipeline that size. Id. 

Rather than making a “bare citation” to Rockies Express, the 

Commission invoked that precedent as an example of 

approving higher initial rates when a project faces greater risks 

from the outset. By contrast, the pipeline projects Petitioners 

cite for support concerned expansion proposals for pipelines 

that had been operational for a year or more.

5

 The Commission 

acted reasonably in denying the requested 14 percent return on 

equity in those cases, where the pipeline companies did not 

face the same risks as non-operational new market entrants.

5 Cheyenne Connector expanded a pipeline that had been in operation 

since 2009. Rockies Express Pipeline, TALLGRASS LEADING

ENERGY SOLUTIONS, https://www.tallgrassenergy.com/Operations_

REX.aspx (last visited Feb. 25, 2022). In Gulfstream Natural Gas 

System, LLC, the Commission denied a higher return on equity for a 

pipeline expansion of a system that had been in service for over 18 

years. 170 FERC ¶ 61,199, ¶¶ 18–20. So too in Cheniere Corpus 

Christi Pipeline, LP, the original pipeline had been in service for a 

year when the Commission denied the higher requested rate for its 

expansion. Corpus Christi Pipeline, CHENIERE, https://www.

cheniere.com/where-we-work/cc-pipeline (last visited Feb. 25, 

2022). 
14

Second, the Commission detailed Petitioners’ objections 

in its Certificate Order and squarely addressed them in 

explaining its reasoning behind treating Mountain Valley as a 

new market entrant. It specifically noted that its reasoning for 

approving lower return on equity rates in extensions of existing 

pipeline systems did not apply here because those pipelines 

“obtained revenues for service on their existing systems.” 

Certificate Order, ¶ 57. 

Finally, the Commission enumerated the specific risks of 

this project: Mountain Valley was not an established pipeline 

company; it did not have an existing revenue base or a proven 

track record; and the Mainline System was not yet operational. 

Id. As a result, FERC found it appropriate to treat Mountain 

Valley as a new market entrant proposing a greenfield pipeline 

“because there are no established operations or revenue streams 

that would reduce the risk to the level experienced by natural 

gas companies whose existing systems are in service.” Id. We 

find that treatment appropriate.

B.

Petitioners also attack the Commission’s Environmental 

Impact Statement as inadequate on two fronts: its discussion of 

potential mitigation measures and the project’s cumulative 

impacts. Under NEPA’s implementing regulations, an EIS 

must include potential mitigation measures that will “avoid, 

minimize, or compensate for effects” of the proposed activity. 

See 40 C.F.R. § 1508.1(s); see also id. §§ 1502.14(e); 

1502.16(a); 1505.3. While NEPA requires an agency to 

consider mitigation measures, significantly, “it does not 

mandate the form or adoption of any mitigation.” Id.

§ 1508.1(s). NEPA also requires that the Commission’s EIS 

consider the “cumulative impacts” of a proposed project. 40 
15

C.F.R. § 1508.7. A “cumulative impact” is defined as an 

environmental impact that “results from the incremental impact 

of the action when added to other past, present, and reasonably 

foreseeable future actions.” Id. 

First, Petitioners contend that the Commission failed to 

take a “hard look” at the environmental consequences of the 

Southgate Project in its corresponding EIS, particularly with 

regard to sedimentation and erosion. Its reliance on measures 

that proved ineffective for the Mainline System and its failure 

to discuss the effectiveness of these measures was arbitrary and 

capricious, in Petitioners’ view. Petitioners rely in part on a 

report from their own expert hydrogeologist, who criticizes the 

measures discussed in the EIS—including silt fences, compost 

socks, water bars, traverse trench drains, and trench breakers to 

prevent stormwater runoff—as ineffective. 

Petitioners’ argument does not accurately reflect the EIS, 

given that the Commission discussed potential mitigation 

measures for erosion and runoff in detail. To mitigate both, the 

Commission noted that Mountain Valley must route water 

discharged from excavation to vegetated land surfaces. EIS 4-

50. Trench breakers (sandbags or foam) would be installed to 

prevent water movement in the pipeline, thereby working to 

inhibit erosion. EIS 2-19. Sediment barriers, like silt fences

and straw bales, as well as trench plugs would be installed and 

maintained throughout construction to prevent erosion. EIS 2-

22. Mountain Valley would then install “[p]ermanent erosion 

control features,” like slope breakers, on steep terrain. EIS 2-

21. While Petitioners’ expert criticizes the Commission’s 

reliance on silt fences, she also noted that they are “not 

effective in steep slope areas,” which is why they had failed for 

Mainline. J.A. 235. Yet, Southgate will traverse flatter terrain 

and silt fences may therefore prove effective. 
16

Further, the EIS distinguishes these measures from those 

that failed for Mountain Valley in the past. Pointing to 

empirical data, it cites 2018 as a record-breaking year for 

precipitation in the region. EIS 1-12. The Commission does

not expect that precipitation level to repeat and therefore, to 

cause the same erosion and sediment control issues. Id. Still, 

to avoid experiencing such issues, Mountain Valley proposed 

monitoring weather conditions during construction and 

adjusting control measures. Id. It will also document the 

effectiveness of its erosion control measures through weekly 

reports and allow FERC representatives on-site to enforce 

compliance. EIS 1-13. Third-party inspectors would have the 

authority to stop work on the pipeline immediately, if needed. 

EIS 1-12, 2-30. As a result, the Commission concluded that 

Mountain Valley’s proposed surface water mitigation 

measures would “adequately avoid or minimize potential 

impacts on surface water resources.” EIS 5-5. 

On the whole, Petitioners’ criticisms miss the point of the 

mitigation measure discussion as an “information-forcing” 

exercise. Mayo v. Reynolds, 875 F.3d 11, 15 (D.C. Cir. 2017) 

(internal quotation marks and citation omitted). Again, NEPA 

does not mandate that the Commission formulate a specific 

mitigation plan, only that it discuss mitigation “in sufficient 

detail to ensure that environmental consequences have been

fairly evaluated.” Robertson v. Methow Valley Citizens 

Council, 490 U.S. 332, 352 (1989). This EIS, fulsome in its 

discussion of potential mitigation measures and differences 

from the Mainline System, meets NEPA’s mark.

Second, Petitioners argue that the Commission failed to 

consider the cumulative impact of the Southgate and Mainline 

System on aquatic resources in the affected area. In their 

account, the Commission purposefully restricted the temporal 

and geographic area of the project in its cumulative impact 
17

consideration to avoid overlap with the Mainline System 

Project. Petitioners express particular concern over the 

increased “turbidity plumes”—cloudy water resulting from 

sediment—that could result from the projects’ overlap. 

Sediment resulting from these plumes may have long-term 

negative impacts on aquatic life and these effects “could be 

additive, if turbidity plumes settled within common stream 

segments.” Pet’rs’ Br. at 41 (quoting EIS 4-243). Chief among 

their concerns is turbidity plumes settling in the Kerr Reservoir, 

which sits downstream of both projects. 

The purpose of the cumulative impact consideration in an 

EIS is to present a realistic picture of a proposed activity’s 

impacts. American Rivers v. FERC, 895 F.3d 32, 55 (D.C. Cir. 

2018). Requiring such a consideration prevents “agencies from 

gaming the system by artificially segmenting significant 

actions into piecemeal, and individually insignificant, 

components.” Id. at 54. Where an agency pays scant attention 

to past actions that have damaged the geographic area at issue 

or discusses cumulative impacts in conclusory phrases, it has 

not met NEPA’s standard. Id. at 55 (agency “fell far short of 

the NEPA mark” in failing to consider past actions that 

damaged the area’s ecosystem); NRDC v. Hodel, 865 F.2d 288, 

289 (D.C. Cir. 1988) (per curiam) (allowing agency’s 

boilerplate analysis of cumulative impacts “to pass muster here 

would eviscerate NEPA”).

As a practical matter, an agency can typically identify the 

location where cumulative impacts are likely to occur by first 

choosing a single “ecoregion” or “watershed.” 6 Consideration 

of Cumulative Impacts in EPA Review of NEPA Documents 

6

“A watershed is a land area where precipitation collects and funnels 

to an outlet—usually a stream.” J.A. 85 (internal quotation marks 

omitted).
18

4.2, U.S. EPA (1999). Though these boundaries “should not 

be overly restricted in cumulative impact analysis,” they should 

also not be so expansive that the “analysis becomes unwieldly 

and useless for decision-making.” Id. Making this selection 

demands a “high level of technical expertise and is properly left 

to the informed discretion of the responsible federal agencies.” 

Kleppe v. Sierra Club, 427 U.S. 390, 412 (1976). 

In addition to naming the relevant geographic area, the 

cumulative impact analysis must identify: “the impact expected 

in that area; those other actions—past, present, and proposed, 

and reasonably foreseeable that have had or will have impact 

in the same area; the effects of those other impacts; and the 

overall impact that can be expected if the individual impacts 

are allowed to accumulate.” Sierra Club v. FERC, 827 F.3d 

36, 49 (D.C. Cir. 2016) (internal quotation marks, citation, and 

numbering omitted). A cumulative impacts analysis will pass 

a “hard look” review if it “contain[s] sufficient discussion of 

the relevant issues and [is] well-considered.” City of Boston 

Delegation v. FERC, 897 F.3d 241, 253 (D.C. Cir. 2018)

(internal quotation marks and citation omitted).

The Commission fulfilled that standard. First, the 

Commission designated “hydrologic unit code-10” (“HUC10”) as the geographic scope for its cumulative analysis on 

surface water resources, which averages to about 130,000 

acres. EIS 4-227, 4-230. Second, the Commission identified 

in-stream activities, including dredging and open pipeline 

crossing techniques, as likely to result in increased turbidity in 

this area. EIS 4-242. It noted that turbidity plumes could travel 

downstream for a few miles, but that the impacts would be felt 

only temporarily, given the limited duration of these in-water 

activities and the plumes’ tendency to disperse within several 

days. Id. Third, FERC named other actions that would likely 

have an impact in the same area, with a particular focus on the 
19

Mainline System Project. EIS 4-236. The Southgate Project 

and Mainline System Project would overlap at two perennial 

streams and one intermittent stream within the Cherrystone 

Creek-Banister River HUC-10 watershed. Id. But the 

Commission stipulated that the Projects’ stream crossings are 

three and a half miles apart, the Projects would not share 

overlapping workspace, and their construction would not take 

place at the same time. Id.; EIS 4-243. Lastly, the Commission 

maintained that the cumulative impacts of the two projects on 

turbidity would be limited because of the geographic and 

spatial distance between the crossings. EIS 4-243. The 

Commission acknowledged that sediment can accumulate 

when turbidity plumes settle in a stream, but found this impact 

unlikely given the projects’ spatial separation and the erosion 

and sediment controls that will be in place. Id. Additionally, 

the Kerr Reservoir is more than 30 miles away from both 

projects, remains outside the geographic scope of the analysis, 

and therefore is likely to face only negligibly increased 

sedimentation as a result. J.A. 886. Thus, in its cumulative 

analysis, the Commission recognized the pertinent issues and 

reasonably concluded that the two projects are geographically 

and temporally separated enough to mitigate any compounded 

effects. 

Such a conclusion aligns with our deference to the 

Commission on issues that demand its technical and scientific 

expertise. Myersville Citizens for a Rural Community, Inc. v. 

FERC, 783 F.3d 1301, 1308 (D.C. Cir. 2015) (“when 

considering FERC’s evaluation of scientific data within its 

technical expertise, we afford FERC an extreme degree of 

deference”) (internal quotation marks and citation omitted). 

What’s more, Petitioners do not marshal compelling evidence 

to counter the Commission’s cumulative impacts analysis. The 

City of Roanoke briefing lists downstream sediment as a 

concern of the Mountain Valley pipeline but does not present 
20

any statistical evidence contradicting FERC’s conclusions. 

J.A. 829–36. Further, the research Petitioners presented in 

their rehearing request, allegedly demonstrating that fine 

sediment can travel hundreds of miles and therefore will 

accumulate between the two Projects, is taken from an 

environmental product company’s website. J.A. 803.7 Upon 

review, the web page in question does not claim that sediment 

may travel hundreds of miles. These sources thus do not call 

into question the Commission’s analysis. 

For the foregoing reasons, we deny the petition for review.

So ordered.

7 Petitioners cite Sediment Transport and Deposition: Fundamentals 

of Environmental Measurements, FONDRIEST ENVIRONMENTAL,

INC., https://www.fondriest.com/environmental-measurements/para

meters/hydrology/sediment-transport-deposition/#std2 (Dec. 5, 

2014).