Gulf South Pipeline Company v. FERC ( 2020 )

United States Court of Appeals
FOR THE DISTRICT OF COLUMBIA CIRCUIT
Argued January 14, 2020 Decided April 10, 2020
No. 19-1074
GULF SOUTH PIPELINE COMPANY, LP,
PETITIONER
v.
FEDERAL ENERGY REGULATORY COMMISSION,
RESPONDENT
On Petition for Review of Orders of the
Federal Energy Regulatory Commission
Michael E. McMahon argued the cause for petitioner.
With him on the briefs were A. Gregory Junge, Sean Marotta,
and Matthew J. Higgins.
Beth G. Pacella, Deputy Solicitor, Federal Energy
Regulatory Commission, argued the cause for respondent.
With her on the brief were Robert H. Solomon, Solicitor, and
Carol J. Banta, Senior Attorney. Robert M. Kennedy Jr.,
Attorney, entered an appearance.
Before: HENDERSON and RAO, Circuit Judges, and
RANDOLPH, Senior Circuit Judge.
Opinion for the Court filed by Circuit Judge RAO.
2
RAO, Circuit Judge: Gulf South Pipeline Company filed an
application with the Federal Energy Regulatory Commission
(“FERC”) in order to build an expansion to its existing pipeline
network. Because the expansion facilities will be dramatically
more expensive to construct than the surrounding facilities
were, Gulf South requested “incremental-plus rates”—also
called “additive rates”—under which all natural gas shippers
who use the new facilities will be charged a higher rate
reflecting the cost of construction. FERC denied the proposed
shipping rates. Instead, FERC effectively approved two
separate rates for using the expansion facilities. Only Entergy
Louisiana, a new shipper that entered into a long-term contract
primarily to use the expansion facilities, will pay a higher rate
reflecting the cost of the expansion. Gulf South’s existing
shippers will pay a fraction of this cost to use the new facilities.
We hold that FERC’s rejection of incremental-plus rates
was arbitrary and capricious. Under FERC’s order, materially
identical shippers will pay dramatically different rates for the
use of the same facilities. FERC failed to justify that disparity,
and its decision violated fundamental ratemaking principles—
namely, that rates should generally reflect the burdens imposed
and benefits drawn by a given shipper. We therefore vacate the
part of FERC’s order denying incremental-plus rates and
remand for further proceedings consistent with this opinion.
We deny Gulf South’s petition for review in all other respects,
including the company’s objections related to its initial rate of
return and depreciation rate.
I.
Gulf South operates an extensive network of natural gas
pipelines in the southeastern United States. This case is about
an application filed by Gulf South under Section 7 of the
3
Natural Gas Act, 15 U.S.C. § 717f, which governs the
construction or expansion of pipeline facilities. To build an
expansion, a company must first receive a “certificate of public
convenience and necessity issued by the Commission.” Id.
§ 717f(c). FERC will grant such a certificate only if it finds the
project “is or will be required by the present or future public
convenience and necessity.” Id. § 717f(e). FERC may “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.” Id. FERC also
reviews initial shipping rates proposed by pipeline companies
for new facilities in Section 7 proceedings, but the
Commission’s orders are meant only “to hold the line” pending
more extensive ratemaking proceedings under Section 4 of the
Natural Gas Act. Atl. Ref. Co. v. Pub. Serv. Comm’n of State of
N.Y., 360 U.S. 378, 391–92 (1959); see also 15 U.S.C. § 717c.
In the Section 7 filing at issue, Gulf South proposed an
expansion within its existing Lake Charles Zone in Louisiana.
The Westlake Expansion Project will consist of a compressor
station, 0.3 miles of pipeline, and a handful of other facilities,
all of which will serve a new power plant owned and operated
by Entergy Louisiana. Gas cannot be delivered to the new
power plant unless a shipper uses the new compressor station,
which in turn will be used only if a shipper is delivering gas to
the plant. To deliver gas to Entergy’s power plant, a shipper
must also use existing Lake Charles facilities—namely, several
miles of an existing pipeline known as the Index 198-3 loop.
However, after natural gas passes through the new compressor
station, it “will, due to pressure differentials, be physically
isolated from the rest of the Lake Charles Zone.” Request for
Rehearing of Gulf South Pipeline Co., LP, at 6 (June 18, 2019)
(“Rehearing Request”).
4
Entergy, which both operates the new power plant and
ships natural gas, entered a precedent agreement with Gulf
South—i.e., a long-term contract—agreeing to purchase the
entire shipment capacity of the expansion facilities for 20
years. Despite that agreement, Gulf South claims existing
shippers in the Lake Charles Zone will at times be able to
secure access to the expansion facilities and deliver gas to
Entergy’s power plant on what is known as a “secondary-firm”
basis. Gulf South Br. 7–11. FERC does not dispute that this
could occur on at least some occasions. See, e.g., Gulf South
Pipeline Co., LP, 166 FERC ¶ 61,089, ¶ 24 (Feb. 1, 2019)
(“Rehearing Order”) (noting that existing shippers will have
“limited” access). 1
FERC approved Gulf South’s application to construct the
expansion facilities but denied three of the company’s
requested rates. See Gulf South Pipeline Co., LP, 163 FERC
¶ 61,124 (May 17, 2018) (“Certificate Order”). First, FERC
rejected Gulf South’s proposed incremental-plus rates. Under
1
More specifically, Gulf South claims that existing shippers will
occasionally be able to “bump” Entergy by taking advantage of
FERC’s open-access policy and priority rules. See Transwestern
Pipeline Co., 99 FERC ¶ 61,356, ¶ 11–12 (June 27, 2002) (holding
that a secondary-firm shipper’s deliveries have priority over primary-
firm shippers like Entergy if the latter fails to schedule a delivery
early enough). Of course, the expansion facilities will be used
exclusively to deliver gas to Entergy’s power plant, so it is not clear
why or when secondary-firm shippers would bump Entergy in order
to sell to Entergy. See Oral Argument at 8:48–9:45 (discussion in
which Gulf South suggested that Entergy might be forced to buy gas
from secondary-firm shippers who secure capacity through FERC’s
priority rules). In any event, all parties agree that on some occasions
shippers other than Entergy might obtain access to the facilities on a
secondary-firm basis, so we assume for the purposes of this appeal
that it can occur.
5
Gulf South’s proposal, all shippers using the expansion
facilities would pay “both the Lake Charles Zone Rates and the
Westlake Expansion Rates.” Id. at ¶ 16. In other words, all
shippers would pay their normal rates for use of the Lake
Charles Zone facilities, but any shipper who uses the expansion
facilities would pay an additional rate reflecting the cost of
construction. FERC rejected this proposal in favor of a scheme
in which only the expansion shipper—i.e., Entergy—would
pay an incremental rate, while the zone’s existing shippers
would pay only their normal Lake Charles Zone rates, even
when they use the expansion facilities. Id. at ¶¶ 21–22. Because
the expansion facilities will be far more expensive to construct
than the existing facilities, the rate disparity is significant.
Entergy will pay more than four times more than other
shippers—a rate of $0.1325 per dekatherm of natural gas, while
existing shippers who use the expansion facilities will pay a
rate of $0.03 per dekatherm. Rehearing Order at ¶ 20.
Next, FERC rejected Gulf South’s requested depreciation
rate of 2.86 percent, which is based on an estimated 35 year
useful life for the new power plant. Certificate Order at ¶ 19.
FERC rejected that proposal in favor of a 1.32 percent rate—
the same depreciation rate set for the existing Lake Charles
Zone. Id. at ¶ 23. Finally, FERC rejected Gulf South’s
proposed initial rate of return. Gulf South had argued that
FERC should incorporate recent changes to the company’s
capital structure, which would allegedly result in an initial rate
of return of 10.81 percent. Id. at ¶¶ 17–18. FERC rejected that
proposal, reasoning that Gulf South must continue to use its last
approved rate of return. Id. at ¶ 24. FERC set these three initial
rates under Section 7; however, Gulf South may request
recalculation of these rates when it next files an application
under Section 4 of the Natural Gas Act, 15 U.S.C. § 717c, at
which point FERC will hold a full evidentiary hearing.
6
Gulf South filed a request for rehearing, which the
Commission denied with respect to all three rates. See
Rehearing Order at ¶¶ 11–30. Gulf South then filed a petition
for judicial review, claiming that FERC’s rejection of these rate
proposals was arbitrary and capricious under the
Administrative Procedure Act (“APA”). See 5 U.S.C.
§ 706(2)(A). We have jurisdiction under the Natural Gas Act’s
judicial review provision. See 15 U.S.C. § 717r(b).
II.
For the reasons discussed below, we conclude that FERC
failed to reasonably explain its denial of incremental-plus rates.
FERC’s precedent suggests that incremental-plus rates are
appropriate when it is possible to track which shippers are
using expansion facilities, thus ensuring that a pipeline
company will not over recover its construction costs. FERC
denied incremental-plus rates here even though Gulf South will
indisputably be able to track which shippers use the expansion
facilities. FERC’s sole rationale for doing so was that the
expansion facilities and existing facilities will be operated as a
single integrated system, but the Commission failed to explain
why that fact supported the denial of incremental-plus rates.
We therefore vacate the Commission’s order in part. However,
we uphold FERC’s denial of Gulf South’s proposed initial rate
of return and depreciation rate. In Section 7 proceedings
governing a project’s initial approval, FERC’s general policy
is to adopt a company’s last approved initial rate of return and
last approved depreciation rate until a full hearing can be held
in the company’s next Section 4 rate case. Gulf South does not
challenge that policy as a general matter, and it has not shown
that a departure was warranted in this case.
7
A.
FERC rejected Gulf South’s proposed incremental-plus
rates under its general policy of disallowing such rates in
“integrated” systems—that is, in systems where the old and
new facilities are operated as a single system. Gulf South
challenges FERC’s integration finding and also argues in the
alternative that FERC should have approved incremental-plus
rates regardless of whether the integration finding was correct.
Although we determine that the record includes substantial
evidence supporting FERC’s factual finding regarding
integration, we hold that FERC did not adequately explain why
this finding justified rejecting incremental-plus rates.
FERC developed the concept of “integration” to guide its
discretion in setting rates for pipeline systems, but it is not a
statutory term. See Battle Creek Gas Co. v. Fed. Power
Comm’n, 281 F.2d 42, 46 (D.C. Cir. 1960) (explaining that “the
Commission has … a general preference for [considering
integration] whenever it may equitably be” done because there
are “apparent advantages” to “recogniz[ing] that a gas pipeline
… is not just a collection of discrete pieces and parts, but an
integrated system serving all of its customers”). Whether
facilities are integrated is a question of fact we review under
the Natural Gas Act’s substantial evidence standard. See
Chippewa & Flambeau Imp. Co. v. FERC, 325 F.3d 353, 360
(D.C. Cir. 2003); Fla. Mun. Power Agency v. FERC, 315 F.3d
362, 367 (D.C. Cir. 2003). “The finding of the Commission as
to the facts, if supported by substantial evidence, shall be
conclusive.” 15 U.S.C. § 717r(b). The standard “requires more
than a scintilla, but can be satisfied by something less than a
preponderance of the evidence.” Minisink Residents for Envtl.
Pres. & Safety v. FERC, 762 F.3d 97, 108 (D.C. Cir. 2014)
(citation and quotation marks omitted).
8
Facilities are integrated when “the pipeline operate[s] the
new facilities and the old facilities as a single system.” Tenn.
Gas Pipeline Co., 80 FERC ¶ 61,070, 61,209 (July 18, 1997).
“Put another way, an expansion facility is integrated when
existing facilities effectuate service on the expansion facility,
or vice versa.” Equitrans, LP, 155 FERC ¶ 61,194, ¶ 10 (May
20, 2016). “Conversely, an expansion facility is not integrated
when it is operationally isolated and does not rely on existing
facilities to effectuate service.” Id. at ¶ 10 n.19 (citing Colo.
Interstate Gas Co., 122 FERC ¶ 61,256, ¶ 60 (Mar. 21, 2008)).
FERC has said that integration “is commonly illustrated by: (1)
an inability to know whether old or new [shippers] are using
either old or new facilities at any particular time; and (2) the
ability of either the old or new customers to take service from
either set of facilities if either set of facilities breaks down.”
Tenn. Gas Pipeline, 80 FERC ¶ 61,070 at 61,209; see also
Battle Creek, 281 F.2d at 47 (describing an integrated system
as one where the “new gas is to be commingled with the old
gas, and both are to be distributed together to all customers”).
That said, FERC has explained that while those two
characteristics are illustrative, the “test for integration is
broader” and focuses more generally on whether the old and
new facilities are operated as a single system. Equitrans, 155
FERC ¶ 61,194 at ¶ 10.
Gulf South argues that the system will not be integrated
because the company is able to determine who is using the
expansion facilities and because old and new shippers cannot
take service from either set of facilities if one breaks down—
the two features that “commonly illustrate[ ]” integration.
Tenn. Gas Pipeline, 80 FERC ¶ 61,070 at 61,209. While this
system does not share those characteristics, there was enough
evidence “under our deferential standard of review,” Fla. Mun.
Power, 315 F.3d at 367, for FERC to find that the facilities will
9
be integrated. There is no dispute that gas delivered to
Entergy’s new power plant will travel almost entirely through
existing pipelines. It is also undisputed that the new facilities
will be segmented by existing facilities. That is, natural gas will
flow back into existing facilities after it passes through the new
compressor station, even if it is kept physically isolated due to
pressure differentials.
FERC has repeatedly emphasized in prior cases that
integration depends largely on whether the new facilities will
rely on the old facilities to effectuate service. See, e.g., Colo.
Interstate, 122 FERC ¶ 61,256 at ¶ 61 (finding that facilities
were not integrated because the “system will not use any
existing pipeline segment on [the existing] mainline system and
there are no interconnections between the facilities that would
allow gas to flow from one system to another” and “the existing
compression facilities on [the existing] mainline system [will
not] be used to effectuate [the expansion project’s] receipts and
deliveries”); Equitrans, 155 FERC ¶ 61,194 at ¶ 12 (finding
that facilities were integrated because “expansion service is
made possible by the existing system”). The Commission’s
factual conclusion regarding integration was consistent with its
precedents in emphasizing that existing facilities will be used
to effectuate service. We should hesitate to displace agency
expertise on complex factual questions, and substantial
evidence supports FERC’s integration finding here.
That factual finding does not, however, end the matter.
Our review turns on whether FERC’s order was reasonable,
and the agency cannot use the term “integration” as a
placeholder for reasoned decisionmaking. We will uphold
FERC’s order only if it “articulate[d] … a rational connection
between the facts found and the choice made.” FERC v. Elec.
Power Supply Ass’n, 136 S. Ct. 760, 782 (2016). FERC has
10
failed to articulate that connection here. Most importantly, the
usual justifications for denying incremental-plus rates in
integrated systems do not apply in this case. In its rehearing
order, FERC offered this explanation for its general policy:
The Commission allows incremental plus pricing for
service utilizing non-integrated facilities because for
such facilities, the Commission can distinguish
which customers are using the new facilities and
which customers are using the existing facilities,
making it possible to ensure that a company is not
over-recovering its actual costs. For integrated
expansions, where it is unclear which customers are
using the new or old facilities, the Commission has
found the appropriate means for preventing the over-
recovery of costs is to authorize pipelines to charge
only an incremental rate to customers subscribing the
expansion service.
Rehearing Order at ¶ 8. That justification has no bearing in this
case. No one disputes that FERC can easily distinguish which
customers are using the new facilities and which are using the
old. The compressor station will be used by every shipper
delivering gas to Entergy’s power plant—and only those
shippers. As a result, there is no risk that incremental-plus rates
will impact existing customers’ service. To the contrary,
existing customers will be charged a higher rate only if they
choose to use the new facilities to ship gas to the new power
plant. No shippers will be charged more for their existing
services, and FERC has failed to explain why there is a risk that
Gulf South will over recover its costs for the expansion.
In addition, Gulf South argues that FERC’s conclusion
was inconsistent with fundamental principles of cost causation,
11
which hold that rates should reflect “the burdens imposed or
the benefits drawn by” a given shipper. BNP Paribas Energy
Trading GP v. FERC, 743 F.3d 264, 267 (D.C. Cir. 2014). We
agree FERC’s order was inconsistent with those principles. As
a general rule, the Commission “may not single out a party for
the full cost of a project, or even most of it, when the benefits
of the project are diffuse.” Id. at 268. Instead, “[p]roperly
designed rates should produce revenues from each class of
customers which match, as closely as practicable, the costs to
serve each class or individual customer.” Ala. Elec. Co-op.,
Inc. v. FERC, 684 F.2d 20, 27 (D.C. Cir. 1982). While “the
Commission may rationally emphasize other, competing
policies and approve measures that do not best match cost
responsibility and causation,” Carnegie Nat. Gas Co. v. FERC,
968 F.2d 1291, 1294 (D.C. Cir. 1992), cost-causation
principles are the default, and “we have approved the
Commission’s departure from traditional cost-causation
principles in only limited circumstances,” United Distrib. Cos.
v. FERC, 88 F.3d 1105, 1186 (D.C. Cir. 1996). Here, the rates
set by FERC do not reflect the benefits drawn by a given
shipper. When Entergy uses the expansion facilities, it will pay
a rate of $0.1325 per dekatherm. When existing shippers use
the same facilities, they will pay their existing Lake Charles
rate of $0.03 per dekatherm.
FERC has offered three responses to Gulf South’s cost
causation argument. While FERC is permitted to depart from
strict cost causation to further competing policies, see Carnegie
Nat. Gas, 968 F.2d at 1293–94, none of the three responses
provides a rational justification for the rate disparity in this
case. First, FERC concluded in its rehearing order that a
departure from cost-causation principles is appropriate to
“reflect[ ] the fact that [existing] shippers are paying for the
underlying facilities under which the pipeline is providing
12
service, such as Gulf South’s existing Index 198-3.” Rehearing
Order at ¶ 19. Similarly, FERC notes that Entergy will be able
to ship gas to other delivery points in the Lake Charles Zone
without paying an added fee. Id. at ¶ 22. Neither fact justifies a
departure from cost-causation principles. While it is true that
existing shippers are already paying for the existing facilities,
those facilities cost a fraction of the price of the expansion. The
expansion facilities will cost $56.2 million to build, while the
net cost of the existing Lake Charles Zone facilities was only
$6.3 million. Id. at ¶ 13. To say that existing shippers should
enjoy access to the more expensive expansion facilities because
they are already paying for the less expensive existing facilities
is not a justification for departing from cost causation. Instead,
it is a simple admission that FERC’s order is a departure from
cost causation. FERC’s assurance that Entergy will be able to
ship gas to other delivery points in the Lake Charles Zone
without paying an added reservation rate is unavailing for the
same reason: Those facilities were a fraction of the cost of the
Westlake Expansion, so Entergy’s open access to the rest of the
Lake Charles Zone does not cure the disparity in rates charged
for use of the expansion facilities.
Second, FERC noted that it has a “longstanding policy …
that shippers should have access to secondary receipt and
delivery points in the zone for which they pay a reservation
charge.” Id. at ¶ 22. This policy gives shippers more “flexibility
in receipt and delivery points.” Id. Yet Gulf South does not
challenge FERC’s policy of allowing secondary-firm shippers
to access expansion facilities. The question is how much those
shippers should pay if they do so. FERC failed to explain why
shippers who take advantage of FERC’s open-access policy
should pay a rate that bears no relation to the cost of the
facilities they use.
13
Third, FERC concluded that incremental-plus rates are
inappropriate because expansion shippers like Entergy “must
pay for the cost of the new capacity constructed for their
needs.” Id. at ¶ 19. “To the extent that the pipeline has
unsubscribed capacity …, then it must make a business
decision as to whether to move forward with the project.
However, an existing shipper’s ability to access the
incremental capacity at a lower rate on a secondary basis in no
way hinders the pipeline’s ability to recover its costs.” Id.
Again, this explanation does not explain the departure from
cost-causation principles. This is not a case where, in FERC’s
words, “the pipeline has unsubscribed capacity,” id., thus
creating a risk that existing customers will be saddled with the
costs of construction. In those circumstances, it may be rational
for FERC to hold that only expansion shippers should pay
higher rates, forcing the company to “make a business decision
as to whether to move forward” despite the risk. Id. Here, Gulf
South has already entered into a precedent agreement
accounting for all of the facilities’ capacity for 20 years, cf.
Myersville Citizens for a Rural Cmty., Inc. v. FERC, 783 F.3d
1301, 1311 (D.C. Cir. 2015) (noting that FERC’s policy is “to
not look behind precedent or service agreements” to evaluate
market need), and FERC has emphasized that as a practical
matter secondary-firm shippers will have only “limited” access
to the facilities, Rehearing Order ¶ at 24. For our purposes, the
question is not whether existing shippers ought to be burdened
with the costs of construction if Entergy fails to support the
project. Rather, the question is how much secondary-firm
shippers should pay if they voluntarily access the new facilities.
Again, FERC has not adequately explained why existing
shippers should pay rates that do not reflect the price of the
facilities they choose to use.
14
FERC’s justifications are further belied by the fact that the
Commission consistently allows incremental-plus rates
whenever it is possible to readily discern which shippers are
using expansion facilities. Indeed, FERC has not identified a
single case where it has denied incremental-plus rates in those
circumstances. Most notably, whenever a company builds a
lateral pipeline, FERC will allow incremental-plus rates
because it can track which facilities shippers are using.
Rehearing Order at ¶ 8 (“The Commission allows incremental
plus pricing for service utilizing non-integrated facilities
because for such facilities, the Commission can distinguish
which customers are using the new facilities and which
customers are using the existing facilities.”). When it comes to
laterals, it does not matter to FERC that existing shippers
already pay for the zone’s existing facilities, nor that FERC has
an open-access policy, nor that pipeline companies must make
business decisions about whether to build a facility without
shifting costs to secondary-firm shippers. Despite those
considerations, FERC allows incremental-plus rates because it
is possible to track the facilities’ use. FERC has not identified
any reason to treat laterals differently from Gulf South’s
proposed expansion.
Indeed, even in integrated systems, FERC has been willing
to allow incremental-plus rates when it is possible to track
which shippers are using which facilities—particularly if doing
so would prevent different shippers from paying an unfair cost
differential. In Texas Eastern Transmission, LP, a pipeline
company proposed to build various new facilities, including
several new pipeline segments. 139 FERC ¶ 61,138, ¶ 7 (May
21, 2012). FERC concluded that the expansion would be
integrated with existing facilities, id. at ¶ 32, but the
Commission was nonetheless concerned that the zone’s
existing rates would “not reflect the significant costs associated
15
with the construction of the project,” id. at ¶ 33. The expansion
rate would have been “over 200 percent greater than the
existing system” rate, which FERC concluded “would not be
appropriate.” Id. The Commission therefore allowed Texas
Eastern to “accomplish its rate objectives in an acceptable
manner by creating a new rate zone with separate maximum
recourse rates” for one of the expansion’s components. Id.
While Gulf South’s primary argument is that FERC should
allow incremental-plus rates within the Lake Charles Zone, the
company has argued in the alternative that FERC should allow
the company to charge the same rates by creating a new rate
zone including only the expansion facilities, as FERC did in
Texas Eastern. FERC claims that Texas Eastern is inapposite
because the “extension was easily distinguishable from the rest
of Texas Eastern’s mainline system. Thus, existing shippers
would only pay the additional cost of the new rate zone if they
elected to transport gas to the new delivery point.” Rehearing
Order at ¶ 15. Yet that is equally true for Gulf South: The
company can discern which shippers use the expansion
facilities and which do not, so existing shippers will, as in
Texas Eastern, “only pay the additional cost of the new rate
zone if they elect[ ] to transport gas to the new delivery point.”
Id.
In the rehearing order, FERC also briefly suggested that it
has a policy of allowing new rate zones only “when th[e]
extension is in a distinct operational and geographical area.” Id.
at ¶ 16. Yet FERC concluded its discussion in the next sentence
without any explanation of why geographic separation is
dispositive. Nor do any of the administrative cases cited by the
Commission explain why geographically distinct facilities
should be treated differently. Rehearing Order at ¶ 16 n.42. We
have no basis to review FERC’s policy because the
16
Commission has said nothing about what the policy means or
why it is justified. See Columbia Gas Transmission Corp. v.
FERC, 448 F.3d 382, 387 (D.C. Cir. 2006) (“It will not do for
a court to be compelled to guess at the theory underlying the
agency’s action; nor can a court be expected to chisel that
which must be precise from what the agency has left vague and
indecisive.”) (quoting SEC v. Chenery Corp., 332 U.S. 194,
196–97 (1947)). Similarly, FERC did not explain why Texas
Eastern’s expansion was geographically distinct but Gulf
South’s is not. Both expansions consist of a variety of new
components attached to or built near existing facilities. The
only apparent distinction is that Texas Eastern’s expansion
included a 15.2 mile pipeline segment that was significantly
longer than the pipeline connecting Entergy’s power plant and
the Index 198-3 loop. See Texas Eastern, 139 FERC ¶ 61,138
at ¶ 7. Again, this court cannot evaluate FERC’s conclusion
without further explanation from the agency.
If there is a rational explanation for why Texas Eastern and
Gulf South should be treated differently, FERC has failed to
articulate it. Both companies proposed to build expansions that
(1) were integrated; (2) were operationally distinct in such a
way that would allow the pipeline to avoid burdening existing
shippers with the costs of construction; and (3) were
dramatically more expensive than the pipeline’s existing
facilities. Indeed, the rate disparity in this case (442 percent) is
far higher than in Texas Eastern. Absent reasonable grounds to
distinguish the two, FERC should have offered Gulf South the
same opportunity to charge incremental-plus rates—whether
through the creation of a new rate zone or as an additional rate
within the existing Lake Charles Zone. See ANR Storage Co. v.
FERC, 904 F.3d 1020, 1025 (D.C. Cir. 2018) (emphasizing
“FERC’s statutory duty … to provide some reasonable
justification for any adverse treatment relative to similarly
17
situated competitors”); W. Deptford Energy, LLC v. FERC, 766
F.3d 10, 20 (D.C. Cir. 2014) (“It is textbook administrative law
that an agency must provide a reasoned explanation for
departing from precedent or treating similar situations
differently.”) (quotation marks and alterations omitted). 2
2
According to FERC, Gulf South failed to exhaust the argument that
its desired rates could be achieved through a new rate zone. We
disagree. The Natural Gas Act provides that “[n]o objection to the
order of the Commission shall be considered by the court unless such
objection shall have been urged before the Commission in the
application for rehearing unless there is reasonable ground for failure
so to do.” 15 U.S.C. § 717r(b). Here, Gulf South indisputably raised
the question of a new rate zone in its rehearing application, thus
satisfying the statute’s exhaustion requirement. See Rehearing
Request at 18 (“[T]he Commission should allow Gulf South the
opportunity to create a new rate zone for the expansion facilities,
consistent with Texas Eastern.”).
Nonetheless, FERC argues that if a party raises an argument for
the first time in its rehearing request (rather than in the initial
application) and FERC rejects it, then the party must raise the
argument again in a second rehearing application. Nothing in the
Natural Gas Act nor our case law requires that a party file two
duplicative rehearing applications. In arguing otherwise, FERC
mistakenly relies on four cases addressing an unrelated issue. Those
cases hold that if FERC modifies its order on rehearing, a party
generally must raise any new complaints in a subsequent rehearing
application, rather than raise them for the first time in court. See
Columbia Gas Transmission Corp. v. FERC, 477 F.3d 739, 741–42
(D.C. Cir. 2007); Canadian Ass’n of Petroleum Producers v. FERC,
254 F.3d 289, 296–97 (D.C. Cir. 2001); Town of Norwood, Mass. v.
FERC, 906 F.2d 772, 774–75 (D.C. Cir. 1990); Tenn. Gas Pipeline
Co. v. FERC, 871 F.2d 1099, 1109–10 (D.C. Cir. 1989). FERC’s
rehearing order did not raise a new source of complaint, and Gulf
South raised its new-rate-zone argument for the first time before the
18
Because FERC did not adequately explain its action, we
hold that the rejection of Gulf South’s proposed incremental-
plus rates was arbitrary and capricious. See 5 U.S.C.
§ 706(2)(A). While Congress has conferred substantial
discretion on FERC in the context of rate setting, our review
under the APA requires the agency to offer reasonable
explanations for the rates it sets. “If we are to hold that a given
rate is reasonable just because the Commission has said it was
reasonable, review becomes a costly, time-consuming pageant
of no practical value to anyone.” Fed. Power Comm’n v. Hope,
320 U.S. 591, 645 (1944) (Jackson, J., dissenting). Here, FERC
set rates that would require shippers to pay amounts vastly
disproportionate to the value of the benefits they draw, and
FERC failed to show why such rates were reasonable. We
therefore vacate the part of FERC’s order rejecting Gulf
South’s proposed incremental-plus rates and remand for further
proceedings. On remand, FERC must also address the
possibility of a new rate zone, as it did in Texas Eastern in
materially similar circumstances. 3
Commission, not in court. FERC was “adequately apprised of” the
objection, Tenn. Gas, 871 F.2d at 1110, and we may consider it on
appeal.
3
In addition to the problems discussed above, Gulf South argues that
FERC failed to respond to the possibility that shippers will game the
system by reserving capacity in the Lake Charles Zone solely to take
advantage of the pricing disparity. Yet FERC reasonably concluded
that such gamesmanship would be an unlikely and risky endeavor
given that Entergy has already contracted for 100 percent of the
facilities’ capacity. Rehearing Order at ¶ 24. FERC’s conclusion was
neither arbitrary nor capricious. Still, that does not absolve FERC of
the problems discussed above. FERC has not explained why existing
19
B.
Next, Gulf South challenges FERC’s denial of its proposed
initial rate of return—i.e., the amount the company is permitted
to charge in addition to its rate base and operating costs “to
ensure that pipeline investors are fairly compensated.” N.C.
Utils. Comm’n v. FERC, 42 F.3d 659, 661 (D.C. Cir. 1994).
FERC set an initial rate of return of 10.41 percent, which is
equal to Gulf South’s last approved rate of return. Rehearing
Order at ¶ 29. Gulf South claims that FERC should have
adjusted that rate to reflect recent changes in the company’s
capital structure.
When setting initial rates of return for integrated
expansion facilities in Section 7 proceedings, FERC’s general
policy is to use the pipeline’s last approved rate. Id. at ¶¶ 27–
28. The company is then free to seek a different rate of return
in its next general rate filing under Section 4 of the Natural Gas
Act. See 15 U.S.C. § 717c. The Supreme Court has consistently
upheld FERC’s policy of deferring the consideration of fact-
intensive rate questions to the company’s next general rate
case, because initial Section 7 proceedings are meant only “to
hold the line awaiting adjudication of a just and reasonable
rate.” Atl. Ref. Co., 360 U.S. at 392; see also United Gas Imp.
Co. v. Callery Properties, Inc., 382 U.S. 223, 227–28 (1965).
Gulf South argues that this general policy is unreasonable
as applied to this case because the pipeline’s last approved rate
of return was set over 20 years ago and because it cannot set a
new rate until 2023. Yet Gulf South had an opportunity to set
a new rate of return in 2015 in its most recent rate case, but it
shippers should pay a lower rate when they secure capacity on the
expansion facilities, even if it will be rare.
20
agreed to settle with FERC and other interested parties without
doing so. Moreover, both Gulf South and FERC agree that the
only reason Gulf South cannot set a new rate of return until
2023 is that the company agreed in its 2015 settlement to a
moratorium on rate filings. FERC Br. 43; Gulf South Br. 15.
Thus, the existing rate of return is the result of Gulf South’s
contractual choices.
Gulf South asks the court to look past the 2015 settlement
because it was a “black box” agreement, a settlement in which
the parties agree to the overarching terms without “explain[ing]
how the rates were derived. In other words, parties to black box
settlements agree to rates without identification or attribution
of costs or adjustments for any particular component of those
rates.” El Paso Nat. Gas Co., 132 FERC ¶ 61,139, ¶ 82 (Aug.
17, 2010). Because prices are determined without specifying
the component parts, no new rate of return is submitted to
FERC for approval. Yet nothing compels parties to agree to
black-box settlements. To the contrary, FERC has repeatedly
encouraged parties to discuss rates of return when reaching
settlements. See Rehearing Order at ¶ 28 (“Given this policy
[of setting Section 7 rates based on the most recent approved
rate of return], the commission encourages companies and
parties in rate cases to address concerns relating to the rate of
return that should be used in calculating initial rates in future
certificate proceedings.”); Transcon. Gas Pipe Line Co., LLC,
156 FERC ¶ 61,022, ¶ 25 (July 7, 2016) (likewise advising
parties to “use that opportunity to address issues of concern
relating to the rate of return”). Other companies have heeded
this advice. See, e.g., E. Shore Nat. Gas Co., 138 FERC
¶ 61,050, ¶ 2 (Jan. 24, 2012) (specifying a rate of return in what
was otherwise a black-box settlement). Gulf South agreed to
settle the 2015 rate case without adjusting its rate of return; it
also agreed to enter an eight year moratorium on rate filings.
21
Gulf South’s freely made contractual choices are no reason to
depart from a longstanding policy, repeatedly upheld by the
Supreme Court, to use the last approved rate of return.
Gulf South also argues that FERC should have adjusted
the rate of return because the formula is so simple it “can be
calculated with a pencil on the back of an envelope.” Reply Br.
25. Specifically, Gulf South claims that its rate of return can be
adjusted by changing a single variable: its capital structure. In
support, Gulf South cites Missouri Public Service Commission
v. FERC, where this court held that it was unreasonable for
FERC to include a premium in a merged pipeline’s Section 7
rates without conducting the particularized inquiry that would
normally be required to include a premium of that kind. 601
F.3d 581, 586–88 (D.C. Cir. 2010). Central to our decision was
the fact that “FERC easily could have resolved the threshold
issue on the basis of the uncontested paper record before it in
the § 7 proceeding.” Id. at 587.
In this case, it was not arbitrary or capricious for FERC to
conclude that a full Section 4 hearing was necessary before
adjusting Gulf South’s rate of return. First, it was reasonable
for FERC to conclude that a full evidentiary hearing would be
necessary to account for variables other than capital structure—
for instance, the company’s growth rates and its “position
within the zone of reasonableness with regard to risk.”
Rehearing Order at ¶ 28. As the Commission notes, rates of
return are determined based on a discounted cash flow method,
which is much more involved than simply adjusting capital
structure figures. See Bos. Edison Co. v. FERC, 885 F.2d 962,
965 (1st Cir. 1989) (Breyer, J.) (explaining the discounted cash
flow method in length). Moreover, FERC was understandably
hesitant to accept Gulf South’s capital structure figures without
a hearing. In the rehearing order, FERC noted that Gulf South
22
inexplicably amended its proposed rate in its rehearing request
from 10.81 to 10.68 percent. Rehearing Order at ¶ 29. Gulf
South explained in its opening brief that it “updated the rate of
return to 10.68 percent, based on its most-recently reported
capital structure” and “[i]n response to a FERC data request.”
Gulf South Br. 15 n.4. The fact that Gulf South’s capital
structure figures fluctuated with more data bolsters FERC’s
position that it should not adjust the approved rate of return
without a hearing to assess Gulf South’s data. This case is
readily distinguishable from Missouri Public Service, where
the relevant analysis could easily be done without a full
hearing. See 601 F.3d at 586–88. We therefore reject Gulf
South’s challenge to the initial rate of return of 10.41 percent,
its last approved rate of return.
C.
Finally, Gulf South challenges the rejection of its proposed
depreciation rate. In this context, “[d]epreciation is generally
defined as ‘the loss, not restored by current maintenance, which
is due to all the factors causing the ultimate retirement of the
property.’” Memphis Light, Gas & Water Div. v. Fed. Power
Comm’n, 504 F.2d 225, 228 (D.C. Cir. 1974) (quoting
Lindheimer v. Ill. Bell Tel. Co., 292 U.S. 151, 167 (1934)).
Pipeline companies may include depreciation charges as “a
legitimate part of [their] operating expenses.” Id. To set
depreciation rates, FERC must “forecast[ ] the probable useful
life of the specific pipeline systems in question, based both on
wear and tear and on the exhaustion of natural resources.” Petal
Gas Storage, LLC v. FERC, 496 F.3d 695, 702 (D.C. Cir. 2007)
(quotation marks omitted). A shorter useful life means a higher
depreciation rate, which in turn “will necessarily increase gas
prices to current consumers.” Memphis Light, Gas & Water
Div., 504 F.2d at 231. As with initial rates of return, FERC’s
23
general policy in Section 7 proceedings involving integrated
expansions is to use the pipeline’s last approved deprecation
rate. See, e.g., Wyo. Interstate Co., Ltd., 119 FERC ¶ 61,251,
¶ 22 (June 7, 2007). Gulf South’s last approved depreciation
rate was based on the 76 year useful life of the Lake Charles
Zone facilities, which results in a depreciation rate of 1.32
percent. Rehearing Order at ¶ 30.
While Gulf South does not challenge FERC’s policy as a
general matter, it argues that this case falls within an exception
for laterals built for a single customer. In those cases, FERC
has approved depreciation rates based on the length of the
contract at issue. See, e.g., Millennium Pipeline Co., LLC, 157
FERC ¶ 61,096, ¶ 32 n.58 (Nov. 9, 2016); Gas Transmission
Nw., LLC, 142 FERC ¶ 61,186, ¶ 17 (Mar. 14, 2013). Gulf
South claims those cases should apply here because the length
of the contract with Entergy is effectively the useful life of the
expansion facilities. Nonetheless, rather than request a
depreciation rate based on the 20 year length of the contract
with Entergy, Gulf South requested a depreciation rate based
on a useful life of 35 years (2.86 percent). Gulf South’s counsel
was asked at oral argument why the company requested a
depreciation rate based on a useful life that is 15 years longer
than the length of the contract, when the company’s entire
argument is premised on the notion that the length of the
contract is the correct benchmark. Counsel responded that Gulf
South “knew that 20 [years] probably wasn’t the right answer,”
so it chose a more “practical and realistic” lifespan
“somewhere between the 76 and the 20” reflecting the “typical
power plant operational life.” Oral Argument at 8:20.
That concession is dispositive. Gulf South does not dispute
that it is generally appropriate in Section 7 proceedings to use
a pipeline’s last approved depreciation rate. Although FERC
24
has recognized an exception for cases in which the length of
the contract is the more appropriate useful life, Gulf South has
conceded that the length of the contract “wasn’t the right
answer” here. Id. Gulf South has offered no rationale nor cited
any precedent for an initial depreciation rate based instead on
a useful life of 35 years. Nor did Gulf South argue in its briefs
that the depreciation rate should be based on the typical power
plant’s operational life. See U.S. ex rel. Davis v. D.C., 793 F.3d
120, 127 (D.C. Cir. 2015) (“[A]rguments raised for the first
time at oral argument are forfeited.”). We therefore reject Gulf
South’s challenge to the 1.32 percent depreciation rate.
***
We grant Gulf South’s petition for review in part and
vacate the part of FERC’s order rejecting incremental-plus
rates. We deny the petition for review in all other respects and
remand for further proceedings. FERC must reconsider
whether to grant incremental-plus rates—whether within the
Lake Charles Zone or through the creation of a new rate zone—
and provide an adequate explanation for its action consistent
with this opinion.
So ordered.