Court Opinion

ID: 6495736
Source: CourtListenerOpinion
Date Created: 2022-06-28 15:00:41.891246+00
Date Added: 2024-06-11T08:49:10.113746
License: Public Domain

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 respondent-
intervenors 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 non-
operational 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. COST-
OF-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” (“HUC-
10”) 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).