167 FERC ¶ 61,052

UNITED STATES OF AMERICA

FEDERAL ENERGY REGULATORY COMMISSION

Before Commissioners: Neil Chatterjee, Chairman;

 Cheryl A. LaFleur, Richard Glick,

and Bernard L. McNamee.

Port Arthur LNG, LLC

PALNG Common Facilities Company, LLC

Port Arthur Pipeline, LLC

Docket No.

Docket Nos.

CP17-20-000

CP17-21-000

CP17-21-001

CP18-7-000

ORDER GRANTING AUTHORIZATIONS UNDER SECTIONS 3 AND 7 OF THE 

NATURAL GAS ACT

(Issued April 18, 2019)

On November 29, 2016, in Docket No. CP17-20-000, Port Arthur LNG, LLC and 

PALNG Common Facilities Company, LLC (collectively, Port Arthur LNG) filed an 

application for authorization under section 3 of the Natural Gas Act (NGA)1 and Part 153 

of the Commission’s regulations2 to site, construct, and operate new facilities for the 

export of liquefied natural gas (LNG) in the vicinity of Port Arthur, Texas (Liquefaction 

Project).

On the same day, Port Arthur Pipeline, LLC (Port Arthur Pipeline) filed an 

application in Docket No. CP17-21-000, under NGA section 7(c)3 and Parts 1574 and 

2845 of the Commission’s regulations, for a certificate of public convenience and 

necessity to construct and operate a new natural gas pipeline system designed to transport 

 1 15 U.S.C. § 717b (2012).

2 18 C.F.R. pt. 153 (2018).

3 15 U.S.C. § 717f (2012).

4 18 C.F.R. pt. 157 (2018).

5 18 C.F.R. pt. 284 (2018).

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Docket No. CP17-20-000, et al. - 2 -

up to 2,000,000 million British thermal units (MMBtu) of natural gas per day from 

interconnections in Cameron Parish, Louisiana, and Orange and Jefferson Counties, 

Texas, to the Liquefaction Project (Texas Connector Project).

On October 16, 2017, Port Arthur Pipeline filed an application in Docket 

No. CP18-7-000, under NGA section 7(c)6 and Parts 1577 and 2848 of the Commission’s 

regulations, for a certificate of public convenience and necessity to construct and operate 

an additional new natural gas pipeline system designed to transport up to 2,000,000

MMBtu of natural gas per day originating in Eunice Parish, Louisiana, to serve as another 

source of feed gas for the Liquefaction Project (Louisiana Connector Project). 

On November 7, 2017, Port Arthur Pipeline filed an amendment to the Texas 

Connector Project application in Docket No. CP17-21-001 which updated and revised 

Port Arthur Pipeline’s pro forma tariff and initial rates as a result of the Louisiana 

Connector Project (Amendment Application).

Port Arthur Pipeline also requests blanket certificates under Part 284, Subpart G of 

the Commission’s regulations to provide open-access transportation service, and under 

Part 157, Subpart F of the Commission’s regulations to perform certain routine 

construction activities and operations, for the Louisiana Connector and Texas Connector

projects.

For the reasons discussed in this order, we will authorize Port Arthur LNG’s 

proposal under section 3 to site, construct, and operate the Liquefaction Project. We will 

also authorize Port Arthur Pipeline’s requested authorizations under section 7(c) of the 

NGA, and Parts 157 and 284 of the Commission’s regulations, to construct and operate 

the Louisiana Connector and Texas Connector projects. These authorizations are subject 

to the conditions discussed herein.

I. Background

Port Arthur LNG, LLC, PALNG Common Facilities Company, LLC, and Port 

Arthur Pipeline, LLC are limited liability companies organized under the laws of the state 

of Delaware, and are wholly-owned subsidiaries of Port Arthur LNG Holdings, LLC, 

which is wholly-owned subsidiary of Sempra Global, which is a wholly-owned 

subsidiary of Sempra Energy. Upon the commencement of operations proposed in its 

 6 15 U.S.C. § 717f.

7 18 C.F.R. pt. 157.

8 18 C.F.R. pt. 284.

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Docket No. CP17-20-000, et al. - 3 -

application, Port Arthur Pipeline will become a natural gas company within the meaning

of section 2(6) of the NGA,9 and will be subject to the Commission’s jurisdiction. As its 

operations will not be in interstate commerce, Port Arthur LNG will not be a “natural gas

company” as defined in the NGA, although it will be subject to the Commission’s 

jurisdiction under NGA section 3.

II. Proposals

A. Liquefaction Project (Docket No. CP17-20-000)

The Liquefaction Project would be located at the same site as Port Arthur LNG, 

L.P.’s proposed import terminal.

10 As proposed, the Liquefaction Project would consist 

of two liquefaction trains with a total production capacity of approximately 13.5 million 

metric tons per annum (MTPA) of LNG (each train capable of producing up to 6.73 

MTPA). Port Arthur LNG also proposes to construct and operate feed gas treatment 

facilities; three LNG storage tanks, each with a net working capacity of approximately 

160,000 cubic meters; a marine facility consisting of two berths for LNG vessels with a 

capacity of up to 266,000 cubic meters of LNG and capable of loading one LNG vessel 

per day; onsite, gas-turbine generators with a generating capacity of 240 megawatts; and 

appurtenant facilities.

Port Arthur LNG received authorization from the U.S. Department of Energy, 

Office of Fossil Energy (DOE/FE) in August, 2015, to export annually up to 517 billion 

cubic feet (Bcf) of natural gas in the form of LNG to countries with which the United 

States has a Free Trade Agreement (FTA), for a term of 25 years.

11 In addition, Port 

Arthur LNG currently has pending before the DOE/FE an application to export LNG to 

 9 15 U.S.C. § 717a(6) (2012).

10 In 2006, the Commission, under section 3 of the NGA, authorized Port Arthur 

LNG, L.P. to site, construct, and operate an LNG import terminal near the City of Port 

Arthur, in Jefferson County, Texas. Port Arthur LNG, L.P. 115 FERC ¶ 61,344 (2006). 

In the same order, the Commission issued Port Arthur Pipeline, L.P. a certificate of 

public convenience and necessity pursuant to section 7(c) of the NGA and Part 157 of the 

Commission’s regulations to construct and operate natural gas pipelines from the outlet 

of the proposed LNG terminal. Since neither applicant had begun construction of the 

authorized facilities within the time frame required, the Commission vacated the 

authorizations in September, 2011. Port Arthur LNG, L.P. and Port Arthur Pipeline, 

L.P., 136 FERC ¶ 61,196 (2011).

11 Port Arthur LNG, LLC, FE Docket No. 15-53-LNG, Order No. 3698 (Filed 

August 20, 2015).

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Docket No. CP17-20-000, et al. - 4 -

other nations with which the United States permits such trade, but has not entered into an 

FTA providing for the national treatment of trade in natural gas.12

B. Louisiana Connector and Texas Connector Projects (Docket No. CP18-

7-000, and Docket Nos. CP17-21-000 & CP17-21-001)

Port Arthur Pipeline proposes to construct a new interstate natural gas pipeline 

system to transport up to a total of 4,000,000 MMBtu per day of natural gas to serve as 

feed gas for the Liquefaction Project. The Port Arthur Pipeline system would comprise

two non-integrated pipelines: the Louisiana Connector Project and the Texas Connector 

Project.

1. Facilities

Louisiana Connector Project (Docket No. CP18-7-000)

The 130.9-mile-long Louisiana Connector Project would transport up to 2,000,000 

MMBtu per day of natural gas from interconnections in Louisiana and Texas to the 

Liquefaction Project, where it would be liquefied for export to foreign markets. 

Specifically, the Louisiana Connector Project would consist of:

130.9 miles of 42-inch-diameter pipeline extending from the Liquefaction 

Project north to interconnections with the facilities of:

o Centana Intrastate Pipeline, LP;

o Texas Eastern Transmission, LP;

o Tennessee Gas Pipeline Company, L.L.C.;

o Market Hub Partners Holding, LLC;

o Pine Prairie Energy Center, LLC;

o Texas Gas Transmission, LLC;

o ANR Pipeline Company; and

o Columbia Gulf Transmission, LLC;

 12 See application pending before DOE/FE in Docket No. 15-96-LNG (Filed 

June 15, 2015).
Docket No. CP17-20-000, et al. - 5 -

a new 89,900 horsepower (hp) compressor station consisting of four gasdriven turbines rated at 22,475 hp each located at milepost (MP) 96.2 in 

Allen Parish, Louisiana; and

appurtenant facilities, including pig launcher/receiver facilities located at 

MP 0, 63.4, 96.2, and 130.9.

The estimated cost of the Louisiana Connector Project facilities is approximately 

$1.2 billion.13 

Texas Connector Project (CP17-21-000 and CP17-21-001)

The 34.2-mile-long Texas Connector Project would transport up to 2,000,000 

MMBtu/d of natural gas from interconnections in Louisiana and Texas to the 

Liquefaction Project, where it would be liquefied for export to foreign markets. 

Specifically, the Texas Connector Project would consist of:

two segments of 42-inch-diameter pipe:

o The 7.6-mile-long southern segment, extending from the 

Liquefaction Project south to interconnections with the facilities of 

the Natural Gas Pipeline Company of America and Kinder Morgan 

Louisiana Pipeline Company in Cameron Parish, Louisiana; and

o The 26.6-mile-long northern segment extending from the 

Liquefaction Project north to interconnections with the facilities of 

Houston Pipeline Company, Texas Eastern Transmission, and 

Florida Gas Transmission Company, as well as underground storage 

facilities in Jefferson County, Texas;

approximately 4.65 miles of lateral pipeline of various diameters;

two new compressor stations, one each for the northern and southern 

segments. The northern compressor station, 50,052 hp total, would consist 

of three natural gas-driven turbine compressors rated at 16,684 hp each; the 

southern compressor station, 15,000 hp total, would consist of three 

electric-driven centrifugal compressors rated at 5,000 hp each; and

appurtenant facilities.

 13 Louisiana Connector Project Application, Exhibit K.

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Docket No. CP17-20-000, et al. - 6 -

The estimated cost of the Texas Connector Project is approximately $825.7 million.14 

2. Open Season and Proposed Services

Port Arthur Pipeline states that it held a binding open season from August 21 

through September 1, 2017, for service on the Louisiana Connector and Texas Connector

projects. In response to the open season, Port Arthur Pipeline states that Port Arthur 

LNG entered into a 20-year precedent agreement for 100 percent of both the Louisiana 

Connector and Texas Connector projects’ capacity at negotiated rates. Based upon this 

level of commitment, Port Arthur Pipeline provided Port Arthur LNG “Foundation 

Shipper” status, which provides certain benefits including the option to elect unilateral 

extensions of the contract term and a contractual right of first refusal.

15

Port Arthur Pipeline requests approval of its pro forma tariff, as revised in its 

amended application in Docket No. CP 17-21-001. Port Arthur Pipeline proposes to 

provide firm and interruptible transportation service on the Louisiana Connector and 

Texas Connector projects under new Rate Schedules FT and IT, respectively. Port 

Arthur Pipeline also proposes to provide Enhanced Hourly Firm transportation service16

under Rate Schedule EHFT, firm and interruptible storage service under Rate Schedules 

FSS and ISS, respectively, Parking and Lending service under Rate Schedule P&L, and 

load management service under rate schedule LMS. Port Arthur Pipeline also proposes a 

fuel retainage percentage for service on the Louisiana Connector and Texas Connector

projects.

3. Blanket Certificates

Port Arthur Pipeline requests a blanket certificate of public convenience and 

necessity pursuant to Part 284, Subpart G of the Commission’s regulations authorizing 

Port Arthur Pipeline to provide transportation service to customers requesting and 

 14 Amendment Application, Exhibit K.

15 See Port Arthur Pipeline’s November 7, 2017 Amendment to the Texas 

Connector Project Application, at 12-13 (Amendment Application), Louisiana Connector 

Project Application at 33. Port Arthur Pipeline states that it is not requesting advance 

approval of any potentially non-conforming provisions in this certificate proceeding. 

16 “Enhanced Hourly Firm Transportation Service” enables a shipper to receive 

1/21 of their daily scheduled quantity of gas per hour. See Amendment Application at 

10.

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Docket No. CP17-20-000, et al. - 7 -

qualifying for transportation service under its proposed FERC Gas Tariff, with pregranted abandonment authorization.17

Port Arthur Pipeline requests a blanket certificate of public convenience and 

necessity pursuant to Part 157, Subpart F of the Commission’s regulations authorizing 

certain future facility construction, operation, and abandonment.18

III. Notice, Interventions, and Comments

Notice of Port Arthur LNG’s application for the Liquefaction Project in Docket 

No. CP17-20-000, and Port Arthur Pipeline’s application for the Texas Connector Project 

in Docket No. CP17-21-000, was published in the Federal Register on December 20, 

2016, with comments, interventions, and protests due on January 3, 2017.

19 Notice of 

Port Arthur Pipeline’s application for the Louisiana Connector Project in Docket 

No. CP18-7-000 was published in the Federal Register on November 3, 2017, with 

comments, interventions, and protests due on November 20, 2017.20 Notice of Port 

Arthur Pipeline’s amendment to the Texas Connector Project application in Docket 

No. CP17-21-001 was published in the Federal Register on December 6, 2017, with 

comments, interventions, and protests due on December 21, 2017.21

Golden Pass Products, LLC and Golden Pass Pipeline, LLC (collectively, Golden 

Pass) filed a timely motion to intervene in the Liquefaction Project, Louisiana Connector 

Project, and Texas Connector Project proceedings. Golden Pass received authorization to 

construct, own and operate an LNG export terminal located approximately two miles 

from the proposed Liquefaction Project, as well as an interstate natural gas pipeline 

system located in Calcasieu Parish, Louisiana, and Jefferson and Orange Counties, 

Texas.22 

Driftwood Pipeline LLC and Driftwood LNG LLC (collectively, Driftwood) filed 

a timely motion to intervene in the Louisiana Connector proceeding. Concurrently with 

this order, Driftwood received authorization to construct an LNG export facility in 

 17 18 C.F.R. § 284.221 (2018).

18 Id. § 157.204 (2018).

19 81 Fed. Reg. 92,809.

20 82 Fed. Reg. 51,233.

21 82 Fed. Reg. 57,593.

22 Golden Pass Products, LLC, 157 FERC ¶ 61,222 (2016).

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Docket No. CP17-20-000, et al. - 8 -

Calcasieu Parish, Louisiana, as well as a 96-mile-long interstate natural gas pipeline 

system that would transport natural gas to Driftwood’s proposed LNG terminal, certain 

segments of which will be collocated with the Louisiana Connector Project. 23

Sabine Pass LNG, L.P., and Sabine Pass Liquefaction, LLC (collectively, Sabine 

Pass), and Cheniere Creole Trail Pipeline, L.P. (Creole Trail), filed a timely motion to 

intervene in the Liquefaction Project, Louisiana Connector Project, and Texas Connector 

Project proceedings. Sabine Pass owns and operates the existing Sabine Pass 

Liquefaction Terminal24 located in Cameron Parish, Louisiana, and have an application 

pending before the Commission to add an additional liquefaction berth to their

liquefaction terminal.

25 Creole Trail owns and operates the Creole Trail Pipeline,26 an 

interstate pipeline system located in Beauregard and Cameron Parishes, Louisiana,

designed to transport gas to the Sabine Pass Liquefaction Project.

In addition, a local landowner, Douglas Pedigo, filed a timely motion to intervene 

and comments in the Texas Connector Project proceeding, and the Coushatta Tribe of 

Louisiana (Coushatta Tribe) filed a timely motion to intervene in the Louisiana 

Connector Project proceeding. Timely, unopposed motions to intervene are 

automatically granted pursuant to Rule 214 of the Commission’s Rules of Practice and 

Procedure.27

Several comments in support of the Liquefaction Project, Texas Connector 

Project, and Louisiana Connector Project were filed. The Coushatta Tribe of Louisiana 

commented on the potential of the Louisiana Connector Project to impact tribal lands.

IV. Discussion

A. Liquefaction Project (Docket No. CP17-20-000)

Because the proposed LNG terminal facilities will be used to export natural gas to 

foreign countries, the construction and operation of the proposed facilities and site of 

 23 Driftwood LNG, LLC, 167 FERC ¶ 61,054 (2019).

24 Sabine Pass Liquefaction, LLC, 139 FERC ¶ 61,039 (2012). 

25 For more information on Sabine Pass’ proposal, see Sabine Pass’ application 

filed in Docket No. CP19-11-000.

26 Cheniere Creole Trail Pipeline, L.P., 142 FERC ¶ 61,137 (2013), reh’g denied

Cheniere Creole Trail Pipeline, L.P., 145 FERC ¶ 61,074 (2013).

27 18 C.F.R. § 385.214 (2018).

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Docket No. CP17-20-000, et al. - 9 -

their location require approval by the Commission under section 3 of the NGA.28 While 

section 3 provides that an application for the exportation or importation of natural gas 

shall be approved unless the proposal “will not be consistent with the public interest,” 

section 3 also provides that an application may be approved “in whole or in part, with 

such modification and upon such terms and conditions as the Commission may find 

necessary or appropriate.”29 NGA section 3(a) also provides that for good cause shown, 

the Commission may make supplemental orders as it may find “necessary or 

appropriate.”30

DOE/FE, pursuant to its authority under NGA section 3, has issued Port Arthur 

LNG authorization to export up to 1.91 billion cubic feet per day (Bcf/d), or 

approximately 10 million metric tons per annum (MTPA), of domestically-produced 

natural gas by vessel to all FTA nations from the proposed Liquefaction Project in Port 

Arthur, Texas, for a term of 25 years.31 DOE/FE’s initial order approving Port Arthur 

LNG’s export volumes states that “[i]n light of DOE’s statutory obligation to grant this 

Application without modification or delay, there is no need for DOE/FE to review other 

arguments asserted by Port Arthur LNG in support of the Application.” 32 

 28 The regulatory functions of section 3 were transferred to the Secretary of Energy 

in 1977 pursuant to Section 301(b) of the Department of Energy Organization Act, Pub. 

L. No. 95-91, 42 U.S.C. § 7101 et. seq. In reference to regulating the imports or exports 

of natural gas, the Secretary subsequently delegated to the Commission the authority to 

approve or disapprove the construction and operation of natural gas import and export 

facilities and the site at which such facilities shall be located. The most recent delegation 

is in DOE Delegation Order No. 00-004.00A, effective May 16, 2006. Applications for 

authorization to import or export natural gas must be submitted to DOE. The 

Commission does not authorize importation or exportation of the commodity itself.

29 For a discussion of the Commission’s authority to condition its approvals of 

LNG facilities under section 3 of the NGA, see, e.g., Distrigas Corporation v. FPC, 

495 F.2d 1057, 1063-64 (D.C. Cir. 1974), cert. denied, 419 U.S. 834 (1974), and Dynegy 

LNG Production Terminal, L.P., 97 FERC ¶ 61,231 (2001).

30 15 U.S.C. § 717b(a) (2012).

31 DOE/FE Order No. 3698-A at 4.

32 DOE/FE Order No. 3698 at 5. Section 3(c) provides that the exportation and 

importation of natural gas to and from countries with which there is in effect a Free Trade 

Agreement “shall be deemed to be consistent with the public interest applications for 

 

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Docket No. CP17-20-000, et al. - 10 -

We have reviewed Port Arthur LNG’s application to determine if the siting, 

construction, and operation of its Liquefaction Project as proposed would not be 

consistent with the public interest.33 The proposed Liquefaction Project is to be located 

entirely on lands owned by Port Arthur LNG. Further, the final Environmental Impact 

Statement (EIS) prepared for the proposed projects finds that most of the direct 

environmental impacts of the proposed facilities are expected to be minor.

34 All adverse 

impacts from construction and operation of the facilities will be reduced to less than 

significant levels if the projects are constructed and operated in accordance with 

applicable laws and regulation and the environmental mitigation measures recommended 

in the final EIS and adopted by this order.35 The final EIS also concludes that reasonably 

foreseeable cumulative impacts from operation of the Liquefaction Project will not be 

significant.

36

In accordance with the Memorandum of Understanding signed on 

August 31, 2018, by the Commission and PHMSA,37 PHMSA undertook a review of 

the proposed facility’s ability to comply with the federal safety standards contained in 

Part 193, Subpart B, of Title 49 of the Code of Federal Regulations. 38 On December 20, 

2018, PHMSA issued a Letter of Determination (LOD) indicating Port Arthur LNG has 

demonstrated that the siting of its proposed LNG facilities comply with those federal 

safety standards. If the proposed Liquefaction Project is subsequently modified so that it 

 

such importation and exportation shall be granted without modification or delay.” 

15 U.S.C. § 717b(c) (2012).

33 See National Steel Corp., 45 FERC ¶ 61,100, at 61,332-33 (1988) (observing 

that DOE, “pursuant to its exclusive jurisdiction, has approved the importation with 

respect to every aspect of it except the point of importation” and that the “Commission’s 

authority in this matter is limited to consideration of the place of importation, which 

necessarily includes the technical and environmental aspects of any related facilities.”).

34 See final EIS at 4-326.

35 Id. at ES-10.

36 Id. at ES-9.

37 FERC, Memorandum of Understanding Between the Department of 

Transportation and the Federal Energy Regulatory Commission Regarding Liquefied 

Natural Gas Transportation Facilities (Aug. 31, 2018), 

https://www.ferc.gov/legal/mou/2018/FERC-PHMSA-MOU.pdf. 

38 49 C.F.R. pt. 193, Subpart B (2018).

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Docket No. CP17-20-000, et al. - 11 -

differs from the details provided in the documentation submitted to PHMSA, further 

review would be conducted by PHMSA.

Port Arthur LNG is proposing to operate its Liquefaction Project under the terms 

and conditions mutually agreed to by its customers and will solely bear the responsibility 

for the recovery of any costs associated with construction and operation of the project. 

Accordingly, Port Arthur LNG’s proposal does not trigger NGA section 3(e)(4).39

In view of the above, we find that Port Arthur LNG’s proposal is not inconsistent 

with the public interest. Therefore, we will grant Port Arthur LNG’s application for 

authorization under section 3 of the NGA to site, construct, and operate its proposed LNG 

terminal facilities.

B. Pipeline Projects

Because the Louisiana Connector and Texas Connector projects’ proposed 

pipeline facilities will be used to transport natural gas in interstate commerce subject to 

the jurisdiction of the Commission, the construction and operation of the facilities are 

subject to the requirements of subsections (c) and (e) of section 7 of the NGA.40

1. Application of the Certificate Policy Statement

The Certificate Policy Statement provides guidance for evaluating proposals to 

certificate new construction.41 In the Certificate Policy Statement, the Commission 

established criteria for determining whether there is a need for a proposed project and 

whether the proposed project will serve the public interest. The Certificate Policy 

Statement explains that, in deciding whether to authorize the construction of major new 

natural gas facilities, the Commission balances the public benefits against the potential 

adverse consequences. The Commission’s goal is to give appropriate consideration to the 

enhancement of competitive transportation alternatives, the possibility of overbuilding, 

subsidization by existing customers, the applicant’s responsibility for unsubscribed 

capacity, the avoidance of unnecessary disruptions of the environment, and the unneeded 

exercise of eminent domain in evaluating new pipeline construction.

 39 15 U.S.C. § 717b(e)(4) (2012) (governing orders for LNG terminals offering 

open access service).

40 15 U.S.C. §§ 717f(c) and 717f(e) (2012).

41 Certification of New Interstate Natural Gas Pipeline Facilities, 88 FERC 

¶ 61,227 (1999), clarified, 90 FERC ¶ 61,128, further clarified, 92 FERC ¶ 61,094 (2000) 

(Certificate Policy Statement).
Docket No. CP17-20-000, et al. - 12 -

Under this policy, the threshold requirement for pipelines proposing new projects 

is that the pipeline must be prepared to financially support the project without relying on 

subsidization from the existing customers. The next step is to determine whether the 

applicant has made efforts to eliminate or minimize any adverse effects the project might 

have on the applicant’s existing customers, existing pipelines in the market and their 

captive customers, and landowners and communities affected by the route of a new 

pipeline. If residual adverse effects on these interest groups are identified after efforts

have been made to minimize them, the Commission will evaluate the project by 

balancing the evidence of public benefits to be achieved against the residual adverse 

effects. This is essentially an economic test. Only when the benefits outweigh the 

adverse effects on economic interests will the Commission then proceed to consider the 

environmental analysis where other interests are addressed.

As noted above, the threshold requirement for pipelines proposing new interstate 

gas pipeline facilities is that the pipeline must be prepared to financially support the 

project without relying on subsidization from its existing customers. As Port Arthur 

Pipeline is a new company, it has no existing customers. As such, there is no potential 

for subsidization of the Louisiana Connector or Texas Connector projects’ facilities by 

existing customers, or the degradation of service to existing customers as a result of the 

projects. Thus, we find that the Louisiana Connector and Texas Connector projects meet 

the threshold no-subsidy requirement of the Certificate Policy Statement.

The proposed Louisiana Connector and Texas Connector projects’ facilities are 

designed to transport gas for liquefaction and export at Port Arthur LNG’s Liquefaction 

Project. No other pipelines, or their captive customers have filed adverse comments 

regarding the Louisiana Connector or Texas Connector projects. Thus, we find that the 

Louisiana Connector and Texas Connector projects will not adversely affect other 

pipelines and their captive customers.

We also find that the Louisiana Connector and Texas Connector projects will have 

minimal adverse impacts on landowners and communities. Of the approximately 34.2

miles of pipeline that would be installed as part of the Texas Connector Project, nearly 53

percent, or 18.29 miles, is proposed to be co-located on existing pipeline right-of-way.42 

In addition, Port Arthur Pipeline states that approximately 95.6 miles, or 73 percent of the 

approximately 131 miles of pipeline that would be installed as part of Louisiana 

Connector projects, will be co-located along existing pipeline or electric transmission 

utility rights-of-way.43

 42 See Texas Connector Project Application, Resource Report 1, Table 1.1-4.

43 See Louisiana Connector Project Application at 6.
Docket No. CP17-20-000, et al. - 13 -

In view of the considerations above, we find that Port Arthur Pipeline has 

demonstrated a need for the Louisiana Connector and Texas Connector projects, and that 

the benefits each project would provide outweigh their adverse effects on existing 

customers, other pipelines and their captive customers, landowners, and surrounding 

communities. Therefore, we find, consistent with the criteria discussed in the Certificate 

Policy Statement and subject to the environmental discussion below, that the public 

convenience and necessity requires approval of Louisiana Connector and Texas 

Connector projects, as conditioned in this order.

2. Blanket Certificates

Port Arthur Pipeline requests a Part 284, Subpart G blanket certificate in order to 

provide open-access transportation services. Under a Part 284 blanket certificate, Port 

Arthur Pipeline will not require individual authorizations to provide transportation 

services to particular customers. Port Arthur Pipeline filed a pro forma Part 284 tariff to 

provide open-access transportation services. Since a Part 284 blanket certificate is 

required for Port Arthur Pipeline to participate in the Commission’s open-access 

regulatory regime, we will grant Port Arthur Pipeline a Part 284 blanket certificate, 

subject to the conditions imposed herein.

Port Arthur Pipeline has also applied for a Part 157, Subpart F blanket certificate. 

The Part 157 blanket certificate gives an interstate pipeline NGA section 7 authority to 

automatically, or after prior notice, perform a restricted number of routine activities 

related to the construction, acquisition, abandonment, and replacement and operation of 

existing pipeline facilities provided the activities comply with constraints on costs and 

environmental impacts.

44 Because the Commission has previously determined through a 

rulemaking that these blanket-certificate eligible activities are in the public convenience 

and necessity,45 it is the Commission’s practice to grant new natural gas companies a Part 

157 blanket certificate if requested.46 Accordingly, we will issue Port Arthur Pipeline the 

requested blanket construction certificate under Part 157 of the Commission’s 

regulations, subject to the conditions imposed herein.

 44 18 C.F.R. § 157.203 (2018).

45 Revisions to the Blanket Certificate Regulations and Clarification Regarding 

Rates, Order No. 686, 117 FERC ¶ 61,074, at P 9 (2006).

46 C.f. Rover Pipeline LLC, 161 FERC ¶ 61,244, at P 13 (2017) (denying a request 

for a blanket certificate where the company’s actions had eroded the Commission’s 

confidence it would comply with all the requirements of the blanket certificate program, 

including the environmental requirements.).

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Docket No. CP17-20-000, et al. - 14 -

3. Rates

a. Initial Recourse Rates

Port Arthur Pipeline proposes to establish separate zone rates for the Louisiana 

Connector and Texas Connector facilities because of the non-integrated nature of the two 

pipeline systems. Port Arthur Pipeline estimates that the total capital cost of construction 

for the Louisiana Connector and Texas Connector projects’ facilities will be 

$825,683,53947 and $1,207,584,005,48 respectively. Port Arthur Pipeline initially 

proposed a $146,140,823 cost of service for the Texas Connector Project and a 

$206,800,419 cost of service for the Louisiana Connector Project, utilizing a capital 

structure of 60 percent debt and 40 percent equity, a cost of debt of 5.7 percent, a return 

on equity of 14.00 percent, a federal tax rate of 35 percent, and a depreciation rate of 2.00 

percent.49 

In a February 6, 2018 response to a staff data request, (February 6 Data Response) 

Port Arthur Pipeline provided adjusted costs of service and recalculated its initial 

incremental recourse rates to reflect changes in the federal tax code, as per the Tax Cuts 

and Jobs Act of 2017,50 which became effective January 2018. Due to the changes to the 

federal tax code, the cost of service for the Texas Connector Project was reduced to 

$135,042,816, and the cost of service for the Louisiana Connector Project was reduced to 

$188,555,221, with correspondingly lower calculated initial charges for firm and 

interruptible services.51 As Port Arthur Pipeline’s calculations in its February 6 Data 

Response reflect the federal tax code that will be in effect when the project goes into 

service, the Commission will use the revised costs of service for the purpose of 

establishing the initial recourse rates, to the extent Port Arthur Pipeline demonstrates that 

it is entitled to an income tax allowance, as further discussed below.

For the Texas Connector Project, Port Arthur Pipeline proposes an initial 

maximum monthly recourse reservation charge of $5.7059 per Dth, and an initial usage 

 47 Amendment Application, Exhibit K.

48 See Louisiana Connector Project Application, Exhibit K.

49 Amendment Application, Exhibits O and P; Louisiana Connector Application, 

Exhibits O and P.

50 Pub. L. No. 115-97, 131 Stat. 2054 (Dec. 22, 2017).

51 See Exhibit P, Part I of Port Arthur Pipeline’s Data Response.

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Docket No. CP17-20-000, et al. - 15 -

charge of $0.0033 per Dth, for firm transportation service under Rate Schedule FT.

52 

Port Arthur Pipeline developed its proposed FT reservation charge using first-year fixed 

costs of $133,519,072, and annual reservation billing determinants of 23,400,000 Dth.53 

Port Arthur Pipeline states that its proposed usage charge reflects variable costs of 

$1,523,744 and billing determinants of 467,200,000 Dth, based on an 80 percent load 

factor of the Texas Connector Project’s annual design throughput. Although Port Arthur 

Pipeline states that the billing determinants are based on an 80 percent load factor of the 

Texas Connector Project’s annual design throughput (daily design capacity of 2,000,000 

Dth, times 365, times 80 percent), Port Arthur Pipeline’s proposed billing determinants 

do not equal a load factor of 80 percent, but instead approximately 64 percent.54

For the Louisiana Connector Project, Port Arthur Pipeline proposes an initial 

maximum monthly recourse reservation charge of $7.8244 per Dth, and an initial usage 

charge of $0.0013 per Dth for firm transportation service under Rate Schedule FT.

55 Port 

Arthur Pipeline developed its proposed FT reservation charge for the Louisiana 

Connector Project using first-year fixed costs of $187,710,599, and annual reservation 

billing determinants of 23,990,400 Dth.56 The proposed usage charge reflects variable 

costs of $844,622 and billing determinants of 656,737,200 Dth, based on a 90 percent 

load factor of the Louisiana Connector Project’s annual design throughput.57

Under Rate Schedule EHTF, Port Arthur Pipeline proposes an initial monthly 

reservation charge of $6.5210 per Dth for service on the Texas Connector Project

facilities and a monthly reservation charge of $8.9422 per Dth for service on the 

Louisiana Connector Project facilities.

58 As noted above, Rate Schedule EHFT provides 

a shipper the right to take its daily scheduled quantity ratably over a 21-hour period rather 

 52 Id.

53 Id. Port Arthur did not use the daily design capacity of the Texas Connector 

Project (2,000,000 Dth) in calculating the proposed reservation charge. Instead, its 

calculation is based on 23,400,000 Dth in annual billing determinants, which is 

approximately 97.5 percent of the project’s 24,000,000 Dth annualized design capacity. 

See Amended Exhibit P, Part 1, Page 2.

54 Id. 

55 See Exhibit P, Part I, Page 1 of Port Arthur Pipeline’s Data Response.

56 Id., Page 2.

57 Id.

58 Id.
Docket No. CP17-20-000, et al. - 16 -

than a 24-hour period. Port Arthur Pipeline does not anticipate having any initial 

customers under Rate Schedule EHFT and does not allocate costs to the service. Instead, 

Port Arthur Pipeline applies the factor of 1.1429 (24 divided by 21) to each zone FT rate 

to calculate a rate that accounts for the costs related to the additional capacity needed to 

provide service under Rate Schedule EHFT. 

Port Arthur Pipeline also proposes rates for Interruptible Transportation (IT)

service, Parking and Lending (P&L) service, and Authorized Overrun Service (AOS), 

derived from a 100 percent load factor rate of the respective zone’s FT reservation and 

usage charges. 

While the Commission generally finds Port Arthur Pipeline’s proposed cost of 

service and initial rates for the Louisiana Connector and Texas Connector projects

acceptable, the Commission will require Port Arthur Pipeline to recalculate its rates based 

on revised billing determinants for its reservation charges. After reviewing Port Arthur 

Pipeline’s workpapers, the Commission finds that Port Arthur Pipeline has not based its 

billing determinants on 100 percent of the design capacity of the pipelines. The 

Commission has a long-standing policy of basing initial rates on the design-capacity of 

the pipeline.59 This approach ensures that a pipeline constructing facilities is placed at 

risk for underutilization of the facilities if it does not contract with customers for the full 

capacity of the pipeline.60 Port Arthur Pipeline states that the design capacities for the 

Louisiana Connector and Texas Connector projects are each 2,000,000 MMBtu, and thus 

Port Arthur Pipeline is directed to design its reservation charges based on this capacity. 

In addition, Port Arthur Pipeline is directed to clarify the billing determinants used to 

establish the usage charges for the Louisiana Connector and Texas Connector projects. 

Subject to the discussion herein, the Commission finds Port Arthur Pipeline’s proposed 

costs of service and initial rates for the Louisiana Connector and Texas Connector

projects reasonable.

4. Federal Income Tax Allowance

Consistent with the D.C. Circuit’s holding in United Airlines, Inc. v FERC,

61 the 

Commission has held that a double recovery of income tax costs results from granting a 

Master Limited Partnership (MLP) a separate income tax allowance and a pre-tax return 

 59 Ruby Pipeline, L.L.C., 128 FERC ¶ 61,224 (2009), order on reh’g 131 FERC 

¶ 61,007 (2010).

60 See Cameron Interstate Pipeline, LLC, 160 FERC ¶ 61,009, at P 11 (2017).

61 827 F.3d 122, 134, 136 (D.C. Cir. 2016) (United Airlines).

(continued ...)
Docket No. CP17-20-000, et al. - 17 -

on equity.

62 Accordingly, the Commission has established a policy that MLPs are 

generally not permitted to recover an income tax allowance in their cost of service. For 

those pass-through business forms that are not MLPs, the Commission continues to 

consider how to resolve the double recovery concern raised by United Airlines.

63

However, the Commission has clarified that a natural gas company organized as a passthrough entity, all of whose income or losses are consolidated on the federal income tax 

return of its corporate parent, is considered to be subject to the federal corporate income 

tax, and is thus eligible for a tax allowance.64 For all other pass-through entities claiming 

an income tax allowance, parties should fully address the double-recovery concern raised 

by the court in United Airlines,

65 including the pass-through entities’ ownership structure, 

where any income tax liability is incurred in that ownership structure, and whether those 

income tax liabilities are reflected in the return on equity. 

 62 SFPP, L.P., Opinion No. 511-C, 162 FERC ¶ 61,228, at PP 21-30 (2018);

Enable Mississippi River Transmission, LLC, 164 FERC ¶ 61,075, at PP 34-35 (2018) 

(Enable); see also Inquiry Regarding the Commission's Policy for Recovery of Income 

Tax Costs, 162 FERC ¶ 61,227 (Revised Policy Statement) (providing guidance that an 

MLP may not recover an income tax allowance), order on reh’g, 164 FERC ¶ 61,030 

(2018)).

63 Revised Policy Statement, 162 FERC ¶ 61,227 at PP 3, 45; Trailblazer Pipeline 

Co., LLC, 164 FERC ¶ 61,074, at PP 30-31 (2018) (Trailblazer).

64 See Enable, 164 FERC ¶ 61,075 at PP 34-35; BP West Coast Products, LLC v. 

FERC, 374 F.3d 1263, at 1289 (D.C. Cir. 2004) (disallowing an income tax allowance for 

an MLP’s corporate unitholders, while explaining that an income tax allowance is 

appropriate in the cost of service of a pass-through subsidiary of a corporation “when 

such a subsidiary does not itself incur a tax liability but generates one that might appear 

on a consolidated return of the corporate group.”). See also Interstate and Intrastate 

Natural Gas Pipelines; Rate Changes Relating to Federal Income Tax Rate, Order 

No. 849, 164 FERC ¶ 61,031 at P 3 (2018) (clarifying that for purposes of the FERC 

Form No. 501-G and limited section 4 filings contemplated by the final rule “a natural 

gas company organized as a pass-through entity all of whose income or losses are 

consolidated on the federal income tax return of its corporate parent is considered to be 

subject to the federal corporate income tax, and is thus eligible for a tax allowance.”).

65 Revised Policy Statement, 162 FERC ¶ 61,227 at PP 3, 45; Trailblazer, 

164 FERC ¶ 61,074 at P 31.
Docket No. CP17-20-000, et al. - 18 -

Here, Port Arthur Pipeline represents that it is a wholly-owned subsidiary of 

Sempra Energy, effective November 29, 2016.

66 To the extent that Port Arthur Pipeline 

can demonstrate in its compliance filing to place its initial rates in-service that all of its 

income or losses are consolidated on the federal income tax return of its corporate parent, 

then Port Arthur Pipeline is permitted an income tax allowance on a stand-alone basis.67 

Consistent with the discussion above, if Port Arthur Pipeline cannot make such a 

showing, then Port Arthur Pipeline must provide other evidence to address the doublerecovery concern raised by the court in United Airlines.

68 To the extent Port Arthur 

Pipeline does not make such a demonstration, the tariff records it files setting forth the 

initial rates for service must reflect rates recalculated to reflect removal of the proposed 

tax allowance and accumulated deferred income tax from its cost of service. If Port 

Arthur Pipeline fails to remove the proposed income tax allowance and accumulated 

deferred income taxes from the initial rates, the filing will be rejected as not being in 

compliance with this order and Port Arthur Pipeline will have to refile those records with 

the appropriate rates and receive Commission approval prior to going into service.

5. Allowance for Funds Used During Construction

Port Arthur Pipeline, a new pipeline company, proposes to calculate its Allowance 

for Funds Used During Construction (AFUDC) based on its proposed debt and equity 

capital structure. This approach is consistent with the accounting guidance we have 

given other newly created companies.69 Consistent with Commission precedent, Port 

Arthur Pipeline is required to capitalize the actual costs of borrowed and other funds used 

for construction purposes, not to exceed the amount of debt and equity AFUDC that 

would be capitalized based on the overall rate of return approved. This will ensure that 

the amounts included in AFUDC are properly capitalized in this project, consistent with 

the Commission’s requirements for newly created companies approved in other cases.

 66 Texas Connector Application, Exhibit D.

67 See City of Charlottesville, Virginia, v. FERC, 774 F.2d 1205 (1985) (describing 

and affirming the Commission’s policy with regard to the recognition of income taxes for 

a pipeline that is part of a consolidated corporate income tax filing).

68 827 F.3d at 134-136. See also Revised Policy Statement, 162 FERC ¶ 61,227 

at P 45.

69 See, e.g., Tiger Pipeline, LLC, 131 FERC ¶ 61,010, at P 80 (2010); Cheniere 

Creole Trail Pipeline, L.P., 115 FERC ¶ 61,331, at PP 41-43 (2006), Port Arthur 

Pipeline, L.P., 115 FERC ¶ 61,344 at P 57.

(continued ...)
Docket No. CP17-20-000, et al. - 19 -

6. Fuel Rates

Port Arthur Pipeline is proposing an in-kind system fuel retention percentage with 

an annual tracker mechanism. Port Arthur Pipeline states that it will make an annual 

filing to true up any differences between (i) the quantity of gas retained through the fuel 

retention charge, and (ii) actual fuel consumed and volumes of gas lost and unaccounted 

for (LAUF) on its system. Port Arthur Pipeline proposes an initial fuel percentage of 

0.98 percent for the Texas Connector Project70 and 1.2 percent for the Louisiana 

Connector Project.71 These percentages are designed to recover actual quantities used in 

compression, as well as LAUF volumes for each project or rate zone. The Commission 

accepts Port Arthur Pipeline’s proposed initial fuel retainage percentages. The proposed 

annual tracker mechanism is addressed below.

7. Service under Rate Schedules FSS, ISS, and LMS 

Port Arthur Pipeline does not propose to construct storage capacity as part of its 

system, but states that it will interconnect with off-system underground natural gas 

storage facilities. Port Arthur Pipeline’s certificate application includes service proposals 

that would require the use of off-system storage capacity for firm storage service under 

Rate Schedule FSS, interruptible storage service under Rate Schedule ISS, and a load 

management service under Rate Schedule LMS. Moreover, section 13.43 of Port Arthur 

Pipeline’s pro forma General Terms and Conditions (GT&C) (Off System Capacity) 

would permit Port Arthur Pipeline to acquire, through transportation agreements, offsystem capacity rights, for operational reasons or to render service for its shippers within 

a zone, under its approved tariff and rates. Section 13.43 of the GT&C states that when 

off-system capacity is not required for operational reasons or to meet firm service 

commitments, Port Arthur Pipeline will offer the off-system capacity to shippers on a

primary firm basis within the zone. Finally, section 13.43 of the GT&C states that Port 

Arthur Pipeline is not precluded from seeking case specific authorization for the 

utilization of off-system capacity by Port Arthur Pipeline for other purposes, nor does it 

preclude Port Arthur Pipeline from releasing any capacity it holds on off-system pipeline 

companies.

Port Arthur Pipeline has not proposed rates for Rate Schedules FSS and ISS. Port 

Arthur Pipeline asserts that its proposed LMS maximum monthly “reservation” rate of 

 70 Texas Connector Project Application at 21.

71 Louisiana Connector Project Application at 22.
Docket No. CP17-20-000, et al. - 20 -

$1.50 per Dth is the maximum it believes it can charge in the market area, and is lower 

than its proposed Rate Schedule P&L monthly “reservation” rate of $0.2065 per Dth.72

Port Arthur Pipeline has not developed rates for FSS and ISS services, and its 

maximum monthly market-based “reservation” rate for LMS service is unsupported. 

Thus, we reject Port Arthur Pipeline’s proposed Rate Schedules FSS, ISS, and LMS and

direct Port Arthur Pipeline to delete these rate schedules and any references thereto from 

its tariff.

Moreover, we note that the Commission’s regulations set forth requirements for 

cost pass-through mechanisms.73 Port Arthur Pipeline has not proposed a tariff-based 

cost recovery mechanism that would meet the requirements of section 154.403 of the 

Commission’s regulations for passing through off-system costs to its customers. This 

rejection is without prejudice to Port Arthur Pipeline filing a rate and tariff proposal for 

Rate Schedule FSS, ISS and LMS services that is consistent with Commission precedent 

and regulations. The filing should include a detailed narrative explanation of how Port 

Arthur Pipeline intends to recover cost-based rates associated with its use of off-system 

capacity, as well as workpapers in Excel format showing all formulas underlying its rate 

derivations. Moreover, if Port Arthur Pipeline seeks to pass through to its customers’

market-based rates charged by off-system storage providers, it must provide a study 

showing that it is not able to exercise market power.

8. Pipeline Safety and Greenhouse Gas Costs

Port Arthur Pipeline proposes tracking mechanisms for cost increases due to any 

new pipeline safety or greenhouse gas regulations issued after Port Arthur Pipeline’s 

initial rates are approved. Section 13.29.3 of the GT&C states that Port Arthur Pipeline

shall file annually to revise a Transmission Pipeline Safety Costs and Greenhouse Gas 

Costs Surcharge for each zone on or before September 30 to become effective 

November 1.

Port Arthur Pipeline’s proposed Transmission Pipeline Safety Costs and 

Greenhouse Gas Costs Surcharge closely resembles modernization trackers that the 

Commission addressed in its policy statement Cost Recovery Mechanisms for 

Modernization of Natural Gas Facilities.

74 In the Cost Recovery Policy Statement, the 

 72 See Texas Connector Project Application at 21; Louisiana Connector Project 

Application at 22.

73 18 C.F.R. § 154.403 (2018).

74 151 FERC ¶ 61,047, clarification denied, 152 FERC ¶ 61,046 (2015) (Cost 

Recovery Policy Statement).
Docket No. CP17-20-000, et al. - 21 -

Commission adopted five guiding principles as the standards a pipeline would need to 

satisfy for the Commission to approve a surcharge such as the one proposed by Port 

Arthur:

1. the pipeline’s existing rates must have been reviewed through an NGA general 

section 4 rate proceeding, a cost and revenue study, or through a collaborative 

effort between the pipeline and its customers;

2. the costs eligible for recovery through the surcharge must generally be limited 

to one-time capital costs incurred to modify the pipeline’s existing system to 

comply with safety or environmental regulations or other federal or state 

government agencies, or costs shown to be necessary for safe, reliable, and/or 

efficient operation of the pipeline;

3. the pipeline must design any proposed surcharge in a manner that will protect 

the pipeline’s captive customers from cost shifts due to the surcharge;

4. the pipeline must include some method to allow a periodic review of whether 

the surcharge and the pipeline’s base rates remain just and reasonable; and

5. the pipeline must work collaboratively with shippers to seek shipper support 

for any surcharge proposal.75

Port Arthur Pipeline has not demonstrated that its proposal meets the standards

laid out in the Cost Recovery Policy Statement. Port Arthur Pipeline’s proposal does not 

offer support for the surcharge from shippers, nor does it offer a method to allow for a 

periodic review of whether the surcharge and the pipeline’s base rates remain just and 

reasonable. Furthermore, the Commission finds it is speculative to anticipate what types 

of costs Port Arthur Pipeline may be subject to under federal, state or local legislation, 

whether such costs should be recoverable, and, if recoverable, the manner in which they 

should be recovered. This action is without prejudice to Port Arthur Pipeline filing a 

proposal in the future if it actually incurs such costs or in compliance with the Cost 

Recovery Policy Statement.76 Consistent with this determination, Port Arthur Pipeline is 

directed to delete references to the Transmission Pipeline Safety Costs and Greenhouse 

Gas Costs Surcharge from its tariff.

 75 Cost Recovery Policy Statement, 151 FERC ¶ 61,047 at P 31.

76 Sierrita Gas Pipeline, LLC, 147 FERC ¶ 61,192, at P 48 (2014).

(continued ...)
Docket No. CP17-20-000, et al. - 22 -

9. Three Year Filing Requirement

Consistent with Commission precedent, Port Arthur Pipeline is required to file a 

cost and revenue study no later than three months after its first three years of actual 

operation to justify its existing cost-based firm and interruptible recourse rates.77 In this

filing, the projected units of service should be no lower than those upon which Port 

Arthur Pipeline’s approved initial rates are based. The filing must include a cost and 

revenue study in the form specified in section 154.313 of the Commission’s regulations 

to update cost of service data.78 Port Arthur Pipeline’s cost and revenue study should be 

filed through the eTariff portal using a Type of Filing Code 580. In addition, Port Arthur 

Pipeline is advised to include as part of the eFiling description, a reference to Docket 

Nos. CP17-21-000, CP17-21-001, and CP18-7-000 and the cost and revenue study.79 

After reviewing the data, the Commission will determine whether to exercise its authority 

under NGA section 5 to investigate whether the rates remain just and reasonable. In the 

alternative, in lieu of this filing, Port Arthur Pipeline may make an NGA general section 

4 rate filing to propose alternative rates to be effective no later than three years after the 

in-service date for its proposed facilities.

10. Negotiated Rate Requirements

Port Arthur Pipeline proposes to provide service on the Louisiana Connector and 

Texas Connector projects to the project shipper under negotiated rate agreements. Port 

Arthur Pipeline must file either its negotiated rate agreement or tariff records setting forth 

the essential terms of the agreements in accordance with the Commission’s Alternative 

Rate Policy Statement80 and negotiated rate policies.81 Port Arthur Pipeline must file the 

 77 See Bison Pipeline, LLC, 131 FERC ¶ 61,013, at P 29 (2010) (Bison); Ruby 

Pipeline, LLC, 128 FERC ¶ 61,224 at P 57; MarkWest Pioneer, L.L.C., 125 FERC 

¶ 61,165, at P 34 (2008).

78 18 C.F.R. § 154.313 (2018).

79 Electronic Tariff Filings, 130 FERC ¶ 61,047, at P 17 (2010).

80 Alternatives to Traditional Cost-of-Service Ratemaking for Natural Gas 

Pipelines; Regulation of Negotiated Transportation Services of Natural Gas Pipelines, 

74 FERC ¶ 61,076 (1996); clarification granted, 74 FERC ¶ 61,194 (1996), order on 

reh'g, 75 FERC ¶ 61,024 (1996).

81 Natural Gas Pipelines Negotiated Rate Policies and Practices; Modification of 

Negotiated Rate Policy, 104 FERC ¶ 61,134 (2003), order on reh’g and clarification, 

 

(continued ...)
Docket No. CP17-20-000, et al. - 23 -

negotiated rate agreements or tariff records at least 30 days, but not more than 60 days, 

before the proposed effective date for such rates.82

11. Pro Forma Rate Updates

Port Arthur Pipeline requests waiver of any Commission regulations necessary to 

allow it to revise its proposed rates prior to the in-service date of the project to reflect 

actual cost information.83 Port Arthur Pipeline’s request for a waiver is denied.

However, Port Arthur Pipeline may propose to modify its initial rates to reflect 

updated cost and rate information by filing an amendment to this certificate proceeding, 

but any changes to initial rates can only take place prior to the project being placed into 

service. Thus, Port Arthur Pipeline should file any such amendment application, 

complete with all necessary supporting information, no later than 60 days prior to its 

anticipated in-service date to afford the Commission time to review and act upon its 

request. If Port Arthur Pipeline chooses to place its project into service before the 

Commission has acted on any amendment request, it will have to file an NGA section 484

rate case in order to change the rates approved in this order. 

12. Pro Forma Tariff 

a. Reservation of Capacity for Future Expansions

Section 13.4.1 of the GT&C (Open Season for Generally Available Capacity)

provides in part: 

(a) Pipeline will allocate firm pipeline capacity in accordance with this

Section 13.4. To the extent Pipeline has available unsubscribed capacity

for which there are no pending requests, Pipeline reserves the right, but

shall not be obligated, to reserve such capacity for open seasons to be held

 

114 FERC ¶ 61,042, reh’g dismissed and clarification denied, 114 FERC ¶ 61,304 

(2006).

82 Pipelines are required to file any service agreement containing non-conforming 

provisions and to disclose and identify any transportation term or agreement in a 

precedent agreement that survives the execution of the service agreement. 18 C.F.R. 

§ 154.112(b) (2018). 

83 Louisiana Connector Application at 36.

84 15 U.S.C. § 717c(d) (2012).

(continued ...)
Docket No. CP17-20-000, et al. - 24 -

within the next six (6) Months for the purpose of limiting or avoiding a

future expansion.

This paragraph is the only reference in Port Arthur Pipeline’s tariff to reserving 

capacity for future expansions. While the Commission permits such reservations of 

capacity, Commission policy requires the tariff include several conditions to ensure that 

“reserved capacity is offered in a not unduly discriminatory manner.” 85 As laid out in 

greater detail in Iroquois Gas Transmission System, these conditions require Port Arthur 

Pipeline to:

post all available capacity so that all shippers may bid on it;

delineate that all capacity may only be reserved for a one-year period from 

the date posted;

provide detailed information in the posting of the reserved capacity;

solicit turnback capacity as a part of the process, to assist parties in 

determining the correct size of any expansion project; and

include solicitation procedures to ensure that excess and turnback capacity 

is posted. 

Port Arthur Pipeline is directed to revise its tariff to include such provisions, consistent 

with Commission precedent.86

b. Right of First Refusal and Net Present Value Standard

Section of the 13.4.3 of the GT&C (Net Present Value Standard) provides in part 

that Port Arthur Pipeline shall award capacity for bids received during an open season to 

shippers whose bids it has determined to have the highest net present value (NPV). 

Section of the 13.4.3 of the GT&C describes NPV as 

the discounted cash flow of incremental revenues per dekatherm to Pipeline 

produced, lost or affected by the requests for service and shall be based 

upon such factors as the term, quantity, date on which the requested service 

is requested to commence, and other factors determined to be relevant by 

Pipeline. (Emphasis added.) 

 85 See, e.g., Iroquois Gas Transmission System, 100 FERC ¶ 61,279 (2002).

86 Id. PP 5-10.
Docket No. CP17-20-000, et al. - 25 -

With respect to bids for capacity subject to a right of first refusal, section 13.4.2(c) 

of the GT&C provides:

If Pipeline is willing to accept a bid, Pipeline shall, no later than fifteen (15) 

Days after the close of the bidding period, notify Shipper of the bid having 

the highest Net Present Value (“NPV”). Shipper shall have ten (10) Days 

after receiving notice to notify Pipeline as to whether it will match the bid 

having the highest NPV and longest term. If the Shipper elects to exercise 

its Right of First Refusal to match the bid with the highest NPV it must 

execute a new Service Agreement containing the terms of that bid, which 

new Service Agreement shall succeed the prior agreement following its 

expiration; provided, however, that Shipper shall not be required to pay any 

rate higher than the maximum applicable rate. (Emphasis added.)

The emphasized language in section 13.4.2(c) of the GT&C is not consistent with 

the Commission’s policy that, in the context of the right of first refusal (ROFR) bidding 

process, “shippers may bid whichever combination of rate and term best represents the 

value they place on the capacity.”87 The Commission further finds that the phrase “and 

other factors determined to be relevant by Pipeline” in section 13.4.3 of the GT&C is 

overbroad and lacks clarity regarding how the NPV should be calculated. Accordingly, 

Port Arthur Pipeline is directed to delete the phrases “and the longest term” from 

section 13.4.2(c) of the GT&C and “and other factors determined to be relevant by the 

pipeline” from section 13.4.3 of the GT&C.

c. ROFR Notification

The Commission has held that both a shipper and the pipeline have the right to 

initiate the ROFR process through issuance of a notification to one another.88 However, 

section 13.4.2 of the GT&C expressly grants this right only to the pipeline, stating in part, 

“if Pipeline provides written notice to Shipper to terminate any Long Term Service 

Agreement for firm transportation at the maximum tariff rate, Shipper will have a right of 

first refusal to retain such firm capacity by complying with the bidding procedures in this 

Section 13.4.” Port Arthur Pipeline is directed to revise section 13.4.2 of the GT&C to be 

consistent with the Commission’s ROFR notification policy.

 87 Atlantic Coast Pipeline, LLC, 161 FERC ¶ 61,042, at P 156 (2017) (citing 

Transcontinental Gas Pipe Line Corp., 105 FERC ¶ 61,365, at P 20 (2003)).

88 Texas Eastern Transmission, LP, 102 FERC ¶ 61,262, at PP 26-28 (2003).

(continued ...)
Docket No. CP17-20-000, et al. - 26 -

d. ROFR Bid Matching

Under the Commission’s policy, a ROFR shipper is permitted to match the best 

third-party bid for all or only a volumetric portion of the open season capacity.89 

However, section 13.4.2(c) of the GT&C provides, in part:

If the Shipper elects to exercise its Right of First Refusal to match the bid 

with the highest NPV it must execute a new Service Agreement containing 

the terms of that bid, which new Service Agreement shall succeed the prior 

agreement following its expiration ....(Emphasis added.)

The emphasized language could be interpreted as inconsistent with the shipper’s 

right to match bids for only a portion of its expiring capacity, and that the ROFR shipper 

does not have a right of contract reduction. Therefore, Port Arthur Pipeline is directed to 

clarify section 13.4.2 of the GT&C to provide that a shipper may notify Port Arthur 

Pipeline of its intent to match the best offer(s) for all or a volumetric portion of its 

capacity.

e. Posting ROFR Capacity

Section 13.4.2(a) of the GT&C provides that Port Arthur Pipeline “shall post the 

capacity [subject to ROFR rights] for bidding on its Internet Web Site no later than onehundred and eighty (180) Days prior to the expiration of the current Service Agreement.” 

The phrase “no later than” implies that Port Arthur Pipeline and a shipper may negotiate 

a deadline by which the ROFR notice must be provided under section 13.4.2(a) of the 

GT&C. While the Commission has permitted the negotiation of the ROFR notice 

deadline, the Commission also requires a stated outer limit on how far in advance of the 

end of the contract the ROFR process may begin.90 This outer limit permits the ROFR 

process to take place relatively close to the time the contract terminates so that existing 

shippers, as well as prospective shippers, are provided a timely opportunity to assess the 

value of capacity.91 It is unclear whether the phrase “no later than” is intended to 

authorize negotiation of the ROFR notice deadline, which must be implemented on a not 

unduly discriminatory basis, and/or whether it is intended to function as a “not earlier 

 89 Mountain Valley Pipeline, LLC, 161 FERC ¶ 61,043, at P 113 (2017); see also 

Dominion Trans., Inc. 111 FERC ¶ 61,135, at PP 18-22 (2005).

90 Gulf South Pipeline Company, LP, 115 FERC ¶ 61,301, at PP 11-13 (2006).

91 Id.
Docket No. CP17-20-000, et al. - 27 -

than” outer limit on the ROFR prior notice.92 Port Arthur Pipeline is required to clarify 

and support its proposed notice date consistent with this discussion and Commission 

precedent.93

f. Operational Balancing Agreements

Section 13.7.1 of the GT&C (Operational Balancing Agreements) provides in 

relevant part that “[p]ipeline may enter into [Operational Balancing Agreements (OBAs)] 

with interstate, intrastate pipelines, or LNG terminals that operate natural gas facilities 

that directly interconnect with Pipeline’s system (hereinafter called “OBA Party”),” and 

lists five conditions under which Port Arthur Pipeline would have no obligation to 

negotiate and execute OBAs with any OBA Party. 

North American Energy Standards Board (NAESB) Wholesale Gas Quadrant 

(WGQ) Version 3.0 Flowing Gas Related Standard 2.3.29 provides that “[a]t a minimum, 

[pipeline] should enter into [OBAs] at all pipeline-to-pipeline (interstate and intrastate) 

interconnects.” Further, the Commission’s regulations provide that “[a] pipeline must 

enter into [OBAs] at all points of interconnection between its system and the system of 

another interstate or intrastate pipeline.”94 Accordingly, Port Arthur Pipeline is directed 

to revise its tariff to comply with NAESB WGQ Version 3.0 Flowing Gas Related 

Standard 2.3.29 and section 284.12(b)(2)(i) of the Commission’s regulations, and delete 

the above-mentioned conditions under which Port Arthur Pipeline would not be obligated 

to negotiate and execute OBAs with any OBA Party.

Section 13.7.1(a) of the GT&C states in part:

For the purpose of minimizing operational conflicts between various 

pipeline facilities with respect to the delivery of gas to and from Pipeline’s 

facilities, Pipeline may enter into OBAs with interstate, intrastate pipelines, 

or LNG terminals that operate natural gas facilities that directly 

interconnect with Pipeline's system (herein called "'“OBA Party”"). 

(Emphasis added.)

 92 E.g., Panhandle Eastern Pipe Line Company, LP, FERC NGA Gas Tariff, 

Fourth Revised Vol. No. 1, GT&C Section 7, Contracting for Service Rights, 1.0.0

provides that, for contracts two years or longer, notice must be provided “[n]ot earlier 

than 18 Months and not later than 12 Months.”

93 See, e.g., Rover Pipeline LLC, 158 FERC ¶ 61,109, at P 135 (2017) (Rover).

94 18 C.F.R. § 284.12(b)(2)(i) (2018).

(continued ...)
Docket No. CP17-20-000, et al. - 28 -

Port Arthur Pipeline is directed to revise its tariff to conform with Commission 

policy and NAESB WGQ Standard 2.3.29 which requires “[a]t at minimum...” pipelines 

to “enter into Operational Balancing Agreements at all pipeline-to-pipeline (interstate and 

intrastate) interconnects.”95

g. Multiple Penalties for the Same Infraction

Sections 13.7.9 (Scheduling Penalties) and 13.10.4(b) (Curtailment and Penalties)

of the GT&C allow penalties to be assessed in addition to any other applicable charges 

and penalties. Commission policy prohibits multiple penalties from being assessed for 

the same infraction.96 Therefore, these sections should be revised to be consistent with

Commission Policy. We also direct Port Arthur Pipeline to revise paragraph 5.2.4 of 

Rate Schedule FT quoted below to ensure that a shipper is not assessed both an 

operational flow order (OFO) penalty and an Excess Hourly Take Penalty for the same 

action:

Quantities taken on behalf of Shipper at the Delivery Point(s) in any hour in 

excess of 1/24 of the Shipper’s daily scheduled quantities shall be subject to 

the Excess Hourly Take Penalty applicable to excess hourly takes when 

either no OFO is in effect at the Delivery Points(s) or such an OFO is in 

effect.

h. Interconnecting Operator OFOs

Section 13.9.1 of the GT&C states in part:

Pipeline reserves and will have the right to issue Operational Flow Orders 

to preserve the integrity of Pipeline’s system, to prevent or respond to a 

force majeure event, to ensure adequate operating pressures, to have 

adequate supplies in the system, to assure adequate fuel and Fuel 

Retainage, to maintain firm services and to stabilize the operation of the 

system.

The above-quoted language in section 13.9.1 of the GT&C is consistent with the 

Commission’s policy that an OFO can be issued only in situations which “threaten or 

could threaten the safe operations or system integrity, of the transportation service 

provider’s system or to maintain operations required to provide efficient and reliable firm 

 95 Rover, 158 FERC ¶ 61,109 at P 130.

96 Id. P 129; Columbia Gas Transmission Corp., 100 FERC ¶ 61,084, at P 201 

(2002).

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Docket No. CP17-20-000, et al. - 29 -

service.”97 Section 13.9.4 of the GT&C states that Port Arthur Pipeline may issue an 

OFO if a directly interconnected operator issues an OFO. This language could allow Port 

Arthur Pipeline to bypass the need to assess whether conditions on its own system as set 

forth in section 13.9.1 of the GT&C of its tariff support issuance of an OFO. Port Arthur 

Pipeline is directed to delete section 13.9.4 of the GT&C from its tariff.

i. Curtailment and Force Majeure

Section 13.10.1 of the GT&C provides in part: 

Pipeline shall have the right to curtail transportation services, in whole or in 

part, on all or a portion of its system in an emergency situation, as 

determined by Pipeline in its sole judgment, or when an unexpected 

capacity loss occurs after Pipeline has scheduled service and Pipeline is 

therefore unable to perform the service that it has scheduled... . In addition, 

Pipeline shall have the right to interrupt or discontinue service at any time 

for reasons of Force Majeure or when, in Pipeline’s sole judgment, capacity 

or operating conditions so require or it is desirable or necessary to make 

modifications or operating changes to its system. (Emphasis added.)

The Commission has found that pipelines may only “curtail” scheduled service in 

an emergency situation or when an unexpected capacity loss occurs after the pipeline has 

scheduled service, and the pipeline is therefore unable to perform the service which it has 

scheduled.98 As quoted above, section 13.10.1 of the GT&C gives Port Arthur Pipeline

the right to curtail services under two sets of circumstances. The first set of 

circumstances, in underlined font, describes events that are clearly emergency situations. 

However, the second set of circumstances, in italicized font, could be interpreted as 

including both emergency and non-emergency situations. The language in italics should 

be revised to clearly indicate that the described circumstances must be emergencies. 

Port Arthur Pipeline is also directed to correct a reference in section 13.10.2(b) of 

the GT&C that incorrectly describes the order in which it will curtail services as set forth 

in “this Section 13.10.2(c)” rather than “13.10.2(b)” which is the appropriate section.

Section 13.10.7(a) of the GT&C provides in part:

In the event Pipeline is unable to make deliveries of the quantities of gas to 

which Shipper has firm entitlements on any Gas Day and to which Shipper 

 97 NAESB, WGQ Definition 1.2.6, v. 3.0.; Rover, 158 FERC ¶ 61,109 at P 127.

98 Ryckman Creek Resources, LLC, 136 FERC ¶ 61,061, at P 68 (2011); MarkWest 

Pioneer, L.L.C., 125 FERC ¶ 61,165 at P 52.
Docket No. CP17-20-000, et al. - 30 -

has nominated for delivery from a Primary Receipt Point to a Primary 

Delivery Point under a firm Rate Schedule, Pipeline shall provide a credit 

applicable to the quantities of gas that were nominated and confirmed by 

Shipper’s supplier, but not delivered; provided, however, Pipeline shall not 

be relieved of the obligation to provide credits for failure to confirm a 

nomination for reasons within its control.

The Commission requires pipelines to provide reservation credits based on the 

amount of primary firm service the shipper nominated, which the pipeline was unable to 

schedule or deliver.99 Therefore, Port Arthur Pipeline is directed to remove the 

requirement from section 13.10.7 of the GT&C that credits must be based only on 

nominated and confirmed quantities that were not delivered. 

j. Operational Purchases and Sales

Section 13.12.11 of the GT&C states in part:

Pipeline is not providing a gas supply service under any Rate Schedule of 

Pipeline’s Tariff. Without limiting the foregoing, Pipeline may buy and 

sell gas to the extent necessary to maintain system pressure and balance, to 

implement the cashout provisions in this Section 13.12 and to perform other 

functions necessary in connection with providing gas transportation service.

The Commission requires pipelines to include in their tariffs specific provisions 

addressing operational sales and purchases of gas.100 These provisions include: (a) the 

specific circumstances in which the pipeline will perform an operational purchase or sale; 

(b) a statement that operational purchases or sales have a lower transportation priority 

than firm transportation and there will be no transportation service associated with its 

operational purchases or sales of gas; (c) a statement that operational sales service is 

unbundled from transportation service; (d) posting and bidding procedures for the sale of 

gas for operational purposes; and (e) a commitment to filing an annual report of sales and 

purchases and revenues derived from the sale of gas.101 The report must indicate the 

 99 SG Resources Mississippi, L.L.C., 153 FERC ¶ 61,364, at P 13 (2015); 

CenterPoint Energy Gas Transmission Co., 144 FERC ¶ 61,195, at P 46 (2013).

100 Rover, 158 FERC ¶ 61,109 at P 132; ANR Pipeline Co., 110 FERC ¶ 61,069, at 

P 57 (2006) (ANR); Colorado Interstate Gas Co., 107 FERC ¶ 61,312, at P 15 (2004), 

order on reh’g, 111 FERC ¶ 61,216 (2005); Dominion Trans., Inc., 106 FERC ¶ 61,029, 

at P 17 (2004).

101 ANR, 110 FERC ¶ 61,069 at P 57.
Docket No. CP17-20-000, et al. - 31 -

source of gas, date of the purchase or sale volumes, purchase or sale price, costs 

and revenues from purchase or sale, and the disposition of the costs and revenues. 

Section 13.12.11 of the GT&C conforms with the first required provision; however, Port 

Arthur Pipeline is required to file revised tariff language that incorporates the remaining 

provisions required for operational sales and purchases of gas. 

k. Force Majeure Definition

Section 13.21.1 of the GT&C, in part, defines a force majeure as “any other cause, 

whether of the kind herein enumerated, or otherwise, not within the control of the party 

claiming suspension and which by the exercise of Good Utility Practice, reasonable care 

and due diligence such party is unable to prevent or overcome.” The Commission has 

defined force majeure outages as events that are both “unexpected and uncontrollable.”102 

Therefore, we direct Port Arthur Pipeline to revise this portion of section 13.21 of the 

GT&C accordingly.

l. Liability 

In various sections of its tariff,103 Port Arthur Pipeline proposes to limit its liability 

to damages resulting from “gross negligence or willful misconduct.” The Commission 

has consistently held that a simple negligence standard is appropriate for the liability and 

indemnification provisions of open access tariffs, as this standard prohibits pipelines from 

limiting their liability in a way that would immunize them from direct damages resulting 

from simple negligence and “gives service providers a powerful incentive to operate their 

systems in a reasonable and prudent manner.”104 The Commission has, however, allowed 

pipelines to limit their liability for simple negligence to direct damages, so that they are

 102 North Baja Pipeline, LLC v. FERC, 483 F.3d 819, 823 (D.C. Cir. 2007), aff’d, 

North Baja Pipeline, LLC, 109 FERC ¶ 61,159 (2004), order on reh’g, 111 FERC 

¶ 61,101 (2005). See also, e.g., Kinder Morgan Louisiana Pipeline LLC, 154 FERC 

¶ 61,145 at P 29 (2016); Algonquin Gas Transmission, LLC, 153 FERC ¶ 61,038 at P 103 

(2015).

103 See, e.g. sections 13.5.1, 13.10.6, 13.14.1, and 13.18 of the GT&C. 

104 See, e.g., Trailblazer Pipeline Co. LLC, 142 FERC ¶ 61,007, at P 8 (2012);

CenterPoint Energy Gas Transmission Co., LLC, 139 FERC ¶ 61,064, at P 19 (2012); 

Orbit Gas Storage, Inc., 126 FERC ¶ 61,095, at P 58 (2009)).
Docket No. CP17-20-000, et al. - 32 -

only liable for indirect, consequential, incidental, or punitive damages where there is 

gross negligence, willful misconduct, or bad faith.105

Port Arthur Pipeline’s proposed liability standard is inconsistent with Commission 

policy, as it immunizes the pipeline from direct damages resulting from simple 

negligence. Therefore, Port Arthur Pipeline is directed to revise the liability standard in 

its pro forma tariff so as to not exclude it from liability for direct damages arising from 

its own simple negligence. 

Section 13.21.5 of the GT&C provides, in part:

Shipper warrants that all upstream and downstream transportation and/or 

service arrangements are in place, or will be in place as of the requested 

effective date of service, and that it has advised the upstream and

downstream operators of the Receipt Point(s) and Delivery Point(s) under

Shipper’s Service Agreement(s) and any quantity and quality limitations for 

each point as specified on Exhibits A and B attached to the effective 

Service Agreement(s) or elsewhere in this Tariff. Shipper agrees to 

indemnify and hold Pipeline harmless for refusal to transport gas hereunder 

in the event any upstream or downstream operator fails to receive or deliver 

gas as contemplated by this Tariff.

Section 13.21.5 of the GT&C, could be interpreted to provide that Port Arthur 

Pipeline would be held harmless if it refuses to transport gas in the event any upstream or 

downstream operator fails to receive or deliver gas, whether or not Port Arthur Pipeline is 

also negligent. This would be inconsistent with Commission’s adoption of a comparative 

negligence standard that would hold the pipeline liable for its proportional share of 

responsibility.106 The Commission has prohibited pipelines from limiting their liability in 

circumstances wherein the pipeline and another party have both acted negligently. Port 

Arthur Pipeline is directed to revise its tariff accordingly.

 105 See, e.g., Bison, 131 FERC ¶ 61,013 at P 37; El Paso Natural Gas Co., 

130 FERC ¶ 61,096, at PP 4-5 (2010); ANR Pipeline Co., 100 FERC ¶ 61,132, at 61,505 

(2002).

106 Petal Gas Storage, L.L.C., 124 FERC ¶ 61,082, at P 28 (2008) (citing Koch 

Gateway Pipeline Co., 65 FERC ¶ 61,338, at 62,619 (1993)).
Docket No. CP17-20-000, et al. - 33 -

m. Fuel Adjustment Mechanism

Section 13.22.4 of the GT&C provides in part:

On or prior to April 1 of each Year, Pipeline will make a filing with the 

Commission to adjust the Fuel Retainage Percentage to reflect the annual 

calculations of the Base Fuel Retainage Percentage and the Fuel Retainage 

Percentage True-Up Adjustment, with such adjustment to the Fuel 

Retainage Percentage to become effective as of May 1 of the same Year.

We approve section 13.22.4 of the GT&C subject to Port Arthur Pipeline revising 

the section to clarify that the filing described therein refers to a limited section 4 filing 

under the NGA. This revision is necessary because section 13.35 of the GT&C (Reports

with Respect to Tariff) describes the annual fuel adjustment filing in section 13.22 of the 

GT&C as a report. The language quoted above in section 13.22.4 of the GT&C could 

therefore be interpreted under section 13.35 of the GT&C as permitting Port Arthur 

Pipeline to change its fuel retention charge only through simply posting and filing such 

changes, rather than making a limited NGA section 4 filing that proposes and supports 

such changes with the opportunity for shippers to review and challenge the basis for the 

changes. Fuel retention charges are rates under the NGA. Posting of changed rates 

cannot be in lieu of any other rate change filing required by NGA section 4.107 In 

addition, Port Arthur Pipeline is directed to delete from section 13.35 of the GT&C the 

reference to a “Fuel Retainage Percentage report in accordance with GT&C’s 

Section 13.22.”

n. Penalty Crediting 

Section 13.25 of the GT&C provides that Port Arthur Pipeline will credit on an 

annual basis to non-offending customers penalty revenues net of costs assessed for 

“unauthorized overruns or under-deliveries, failures to abide by an OFO or curtailment 

order, takes in excess of scheduled quantities and other misconduct...” Section 13.25 

further states that “[i]f such penalty revenue net of costs for a Year, plus any amounts 

carried over from prior Years, is less than $400,000, then Port Arthur Pipeline may carry 

such balance of revenue forward to the next Year.”

Section 13.25 of the GT&C does not provide for payment of interest on net 

penalty revenues held by Port Arthur Pipeline. The Commission finds that Port Arthur 

Pipeline’s proposal not to credit interest on accumulated penalty revenue is inconsistent 

with the Commission’s goal in Order No. 637 to eliminate the pipelines’ financial 

 107 See ANR Pipeline Co., 139 FERC ¶ 61,238, at P 157 (2012) (rejecting a 

proposed posting-only fuel rate proposal).

(continued ...)
Docket No. CP17-20-000, et al. - 34 -

incentive to retain penalty revenues.108 Consistent with Commission policy,109 Port 

Arthur Pipeline must revise its tariff to provide that it will credit the penalty revenues 

including the interest that it has accrued to shippers in a manner consistent with 

Commission regulations.110

o. Interruptible Transportation Revenue Sharing

Section 13.26 of the GT&C (Interruptible Transportation and Storage, Load

Management and Authorized Overrun Service Revenue Sharing) provides that the 

pipeline will credit revenues under Rate Schedules IT, P&L, and AOS (among others): 

to each of Pipeline’s firm transportation and storage service Shippers 

(including a firm Shipper that pays a Negotiated Rate to the extent 

negotiated by Pipeline and Shipper on a not unduly discriminatory basis) 

based on the Shipper’s pro rata share of total MDTQs and MDWQs in all of 

the Pipeline’s firm transportation and storage Service Agreements. 

The Commission’s long-standing policy regarding new interruptible services 

requires either a 100 percent credit of the interruptible revenues, net of variable costs, to 

maximum rate firm and interruptible customers or an allocation of costs and volumes to 

these services.111 Port Arthur Pipeline has chosen the crediting option. However, Port 

Arthur Pipeline does not propose to provide credits to maximum rate interruptible 

customers, and although proposing to credit interruptible revenues on a yearly basis, does 

 108 Regulation of Short-Term Natural Gas Transportation Services and Regulation 

of Interstate Natural Gas Transportation Services, Order No. 637, FERC Stats. & Regs. 

¶ 31,091 (cross-referenced at 90 FERC ¶ 61,109), clarified, Order No. 637-A, FERC 

Stats. & Regs. ¶ 31,099 (cross-referenced at 91 FERC ¶ 61,169), reh’g denied, Order 

No. 637-B, 92 FERC ¶ 61,062 (2000), aff’d in part and remanded in part sub 

nom. Interstate Natural Gas Ass’n of America v. FERC, 285 F.3d 18 (D.C. Cir. 

2002), order on remand, 101 FERC ¶ 61,127 (2002), order on reh’g, 106 FERC ¶ 61,088 

(2004), aff’d sub nom. American Gas Ass’n v. FERC, 428 F.3d 255 (D.C. Cir. 2005).

109 See, e.g. Elba Express Co., L.L.C., 119 FERC ¶ 61,015, at P 42 (2007); 

Algonquin Gas Trans. Co., 98 FERC ¶ 61,211, at 61,788-89 (2002); Natural Gas 

Pipeline Co. of America, 101 FERC ¶ 61,200, at P 97 (2002).

110 18 C.F.R. § 154.501(d) (2018). 

111 See, e.g., National Grid LNG LLC, 165 FERC ¶ 61,031, at P 29 (2018); Creole 

Trail LNG, L.P., 115 FERC ¶ 61,331, at P 27 (2006); Entrega Gas Pipeline Inc., 

112 FERC ¶ 61,177, at P 51 (2005).

(continued ...)
Docket No. CP17-20-000, et al. - 35 -

not propose to pay interest on these funds that it may retain for up to twelve (12) months. 

The Commission requires Port Arthur Pipeline to pay interest on the accumulated 

balances consistent with Commission regulations,112 and to include maximum rate 

interruptible customers in its revenue crediting proposal.

Moreover, with regard to permitting negotiated rate shippers to receive such 

credits, the Commission has held that a pipeline may agree to provide shippers paying 

negotiated rates with credits after eligible recourse rate shippers have been credited with 

100 percent of interruptible revenues net of variable costs.113 Negotiated rate shippers 

may receive such credits as a component of an individually negotiated rate rather than by 

virtue of the Commission’s policy on interruptible revenue crediting. Accordingly, as 

provisions of a negotiated rate, such credits are required to be reported in a negotiated 

rate tariff filing. Therefore, we direct Port Arthur Pipeline to remove from section 13.26

of the GT&C provisions referring to the eligibility of negotiated rate shippers to receive 

interruptible revenue credits.

p. NAESB Standards

Port Arthur Pipeline reflects tariff provisions in section 13.38 of the GT&C 

(NAESB) implementing the NAESB WGQ Version 3.0 business practice standards that 

the Commission incorporates by reference in its regulations.114 In the time since Port 

Arthur Pipeline filed its proposed tariff in this proceeding, the Commission adopted the 

new NAESB WGQ Version 3.1 business practice standards.115 Thus, we direct Port 

Arthur Pipeline to file revised tariff records, no less than 60 days prior to its in-service 

date, implementing the NAESB WGQ Version 3.1 business practice standards. Further, 

Port Arthur Pipeline is directed to revise its tariff accordingly to:

1. include standard 0.2.5 in a section titled “Definitions:” under the heading 

“Additional Standards: – General:” in section 13.8 of the GT&C;

 112 18 C.F.R. § 154.501(d) (2018).

113 Wyoming Interstate Co., Ltd., 121 FERC ¶ 61,135, at P 9 (2007).

114 18 C.F.R. § 284.12(a) (2018).

115 Standards for Business Practices of Interstate Natural Gas Pipelines, Order 

No. 587-Y, 83 Fed. Reg. 62,242 (Dec. 3, 2018), 165 FERC ¶ 61,109 (2018). Under 

Order No. 587-Y, interstate natural gas pipelines are required to file compliance filings 

with the Commission by April 1, 2019, and are required to comply with the Version 3.1 

standards incorporated by reference in this rule on and after August 1, 2019. 
Docket No. CP17-20-000, et al. - 36 -

2. remove standard 0.2.5 from section titled “Gas/Electric Operational 

Communications:” in section 13.8 of the GT&C; and

3. remove standard 5.3.73 from section titled “Standards Incorporated by 

Reference:” in section 13.8 of the GT&C, as the text of the standard is 

already included in section 13.11.9 of the GT&C (Capacity Release -

Requests to Purchase Capacity). 

q. Off-system Capacity

Section 13.43 of the GT&C (Off-System Capacity) provides:

Pipeline may enter into a transportation agreement(s) with other interstate 

and intrastate pipeline companies to acquire transportation or storage 

capacity or rights (“off-system capacity”). In the event that Pipeline 

acquires off-system capacity, Pipeline will use such capacity for operational 

reasons or to render service for its Shippers within a Zone. In the event that 

Pipeline uses off-system capacity to render service for its Shippers, it will 

only render service to the Shippers within the Zone on the acquired 

capacity pursuant to this Tariff and subject to Pipeline’s approved rates, as 

such tariff and approved rates may change from time to time. For purposes 

of transactions entered into subject to this GT&C Section 13.43, the 

“Shipper-Must-Have-Title” requirement is waived. When off-system 

capacity is not required for operational reasons or to meet firm service 

commitments, Pipeline will offer the off-system capacity to Shippers on a 

primary firm basis within the Zone. This GT&C Section 13.43 does not 

preclude Pipeline from seeking case specific authorization for the 

utilization of off-system capacity by Pipeline for other purposes, nor does it 

preclude Pipeline from releasing any capacity it holds on off-system 

pipeline companies.

We find this language to be consistent with the Commission’s Texas Eastern

policy concerning the acquisition of upstream capacity by interstate pipelines.116 

Therefore, we will grant a generic waiver of the “shipper must hold title” policy for any 

such transportation that the pipeline subsequently provides.

 116 Texas Eastern Transmission Corp., 93 FERC ¶ 61,273 (2000), reh’g denied, 

94 FERC ¶ 61,139 (2001).

(continued ...)
Docket No. CP17-20-000, et al. - 37 -

V. Environmental Analysis

To satisfy the requirements of the National Environmental Policy Act of 1969 

(NEPA),117 Commission staff evaluated the potential environmental impacts of the 

proposed projects in an EIS. The U.S. Army Corps of Engineers (USACE), Galveston 

District, U.S. Coast Guard, U.S. Environmental Protection Agency (EPA), U.S. 

Department of Transportation (DOT), Pipeline and Hazardous Materials Safety 

Administration (PHMSA), and DOE participated as cooperating agencies in the 

preparation of the EIS. Cooperating agencies have jurisdiction by law or special 

expertise with respect to resources potentially affected by the proposals and participate in 

the NEPA analysis. 

Commission staff issued the draft EIS on September 28, 2018, which addressed 

the issues raised during the scoping period and up to the point of publication. Notice of 

the draft EIS was published in the Federal Register on October 5, 2018,118 establishing a 

45-day public comment period ending on November 19, 2018. The Notice of Availability 

of the Draft Environmental Impact Statement for the Proposed Port Arthur Liquefaction 

Project, Texas Connector Project, and Louisiana Connector Project was mailed to the 

environmental mailing list for the projects. Commission staff held three public comment 

sessions between October 16 and 18, 2018, to receive comments on the draft EIS.119 A 

total of 17 people commented at the sessions. In addition, 17 parties submitted a total of 

22 letters in response to the draft EIS. In addition, on November 30, 2018, Port Arthur 

LNG and Port Arthur Pipeline filed responses to several comments on the draft EIS. The 

transcripts of the public comment sessions and all written comments on the draft EIS are 

part of the public record for the projects.

On January 31, 2019, Commission staff issued the final EIS for the projects, and a 

public notice of the availability of the final EIS was published in the Federal Register on 

February 6, 2019,

120 and mailed to the environmental mailing list for the projects.121 The 

final EIS addresses geology; soils; water resources; wetlands; vegetation; wildlife and 

aquatic resources; threatened, endangered, and other special status species; land use, 

 117 42 U.S.C. §§ 4321 et seq. (2012). See also the Commission’s NEPAimplementing regulations at Title 18 of the C.F.R., Part 380.

118 83 Fed. Reg. 50,362.

119 Commission staff held the public comment sessions in Kinder and Sulfur, 

Louisiana, and Port Arthur, Texas.

120 84 Fed. Reg. 2221.

121 The distribution list is provided in Appendix A of the final EIS.
Docket No. CP17-20-000, et al. - 38 -

recreation, and visual resources; socioeconomics; cultural resources; air quality and 

noise; safety; cumulative impacts; alternatives; and all substantive comments received on 

the draft EIS. The final EIS concludes that construction and operation of the projects will 

result in some adverse environmental impacts, but impacts will be reduced to less-thansignificant levels with the implementation of Port Arthur Pipeline and Port Arthur LNG’s

proposed, and Commission staff’s recommended, mitigation measures which are 

included as conditions in the appendix to this order, as discussed below. No adverse 

comments concerning the final EIS have been filed. Resource areas addressed in the 

final EIS are addressed below.

1. Geology

The overall effect of the Liquefaction Project, the Texas Connector Project, and 

Louisiana Connector Project on topography and geology would be minor. Geologic 

impacts would be limited to construction activities and would include disturbance of 

slopes within the work areas.122 However, some hazards such as severe flooding, storm 

surges, high winds, erosion along the shoreline and docking facilities, and potential site 

access interruptions could affect the Liquefaction Project during operation.123 Port 

Arthur LNG has incorporated structural and mechanical elements into the design of the 

liquefaction facilities.

124 Further, Port Arthur LNG would construct a storm surge barrier 

of improved soil and structural clay to a top elevation of 20 feet.125 Port Arthur LNG 

would also monitor foundations and other critical facilities to ensure they are maintained 

within acceptable limits.126 Along the pipelines, Port Arthur Pipeline would implement 

buoyancy control measures such as concrete-coated piping, anchors, or aggregate-filled 

saddle bags to weigh the pipe in wet areas, and would periodically monitor the pipeline 

right-of-way during operation to aid in identification of subsidence-related conditions that 

may require maintenance.127 Port Arthur LNG and Port Arthur Pipeline do not anticipate 

that any blasting will be required during construction of the projects.

128 Based on Port 

 122 Final EIS at 5-1.

123 Final EIS at 5-1.

124 Final EIS at 5-1.

125 Final EIS at 5-3.

126 Final EIS at 4-6.

127 Final EIS at 5-2.

128 Final EIS at 5-2.

(continued ...)
Docket No. CP17-20-000, et al. - 39 -

Arthur LNG’s and Port Arthur Pipeline’s proposed mitigation and design criteria, and 

Commission staff’s recommended mitigation measures, included in the appendix to this 

order, the final EIS concludes that the Liquefaction Project, the Texas Connector Project,

and Louisiana Connector Project will not significantly impact or be impacted by 

geological conditions in the area.

2. Soils

Construction of the Liquefaction Project, the Texas Connector Project, and 

Louisiana Connector Project could affect soil resources by increasing the potential for 

erosion, compaction, mixing of topsoil, and rutting.129 The Liquefaction Project site and

dredge disposal areas contain clay and peat soils prone to compaction.130 In order to 

increase the load bearing capacity of soils along the heavy haul road, an engineered grout 

would be added to the subsoil that would permanently alter the physical characteristics of 

7.5 acres of soils at the liquefaction facilities.131 Operation of the compressor stations 

and other aboveground facilities along the pipelines for the Louisiana Connector and 

Texas Connector projects would permanently affect 105.7 acres of prime farmland but 

would not result in a significant reduction of usable prime farmland soils in the area.132

In addition to the earthen berm, about 4.4 million cubic yards of fill would be used on the 

remainder of the liquefaction facilities site. Port Arthur LNG would further armor the 

Port Arthur Canal adjacent to the site by means of riprap or other erosion prevention 

measures, and would develop a Shoreline Protection Report to address potential shoreline 

erosion that may occur during operations in the shoreline zone.133 

In response to the EPA’s June 30, 2016 comments on Port Arthur LNG’s draft 

resource reports 1 and 10,, Port Arthur LNG committed to resampling sediments at the 

landward component of the marine offloading facility prior to dredging and disposal. 

Environmental Condition 17 in the appendix to this order requires Port Arthur LNG to 

provide the EPA, USACE, Texas Commission on Environmental Quality, and Texas 

Railroad Commission with this final soil and sediment analysis from the area within the 

ship canal at the marine berth, construction dock, material offloading facility, and 

landward component of the material offloading facility for review. This condition also 

 129 Final EIS at 5-2.

130 Final EIS at 5-2.

131 Final EIS at 5-3.

132 Final EIS at 5-2.

133 Final EIS at 5-3.

(continued ...)
Docket No. CP17-20-000, et al. - 40 -

requires Port Arthur LNG to file its consultation with these agencies with the 

Commission.

3. Water

Potential impacts on groundwater resources are anticipated to be minor and 

temporary. Most construction activities associated with the liquefaction and pipeline 

facilities would involve shallow, temporary, and localized excavation, with the exception 

of concrete and steel piles for LNG vessel loading facilities and LNG tanks. Piles 

required for the LNG storage tanks and LNG ship loading and berthing areas would be 

driven to a depth no lower than 160 feet and are not expected to have direct impacts on 

the underlying aquifer. 134 During construction of the Louisiana Connector and Texas 

Connector projects, shallow groundwater could be encountered within the first 3 feet 

below grade within Jefferson and Orange Counties, Texas and in Cameron, Calcasieu, 

and Beauregard Parishes, Louisiana, and should Port Arthur Pipeline need to pump water

from a pipeline trench, it would be pumped through filter bags prior to discharge.135 No 

drinking water wells or identified springs are within 150 feet of the Liquefaction Project. 

There are no known groundwater withdrawal wells, drinking water wells, designated well 

head protection areas, or springs within 150 feet of the Texas Connector Project in Texas 

and Louisiana. There are 16 known groundwater withdrawal or drinking water wells 

within 150 feet of the Louisiana Connector Project in Louisiana, and none in Texas.136 

Construction of the Liquefaction Project, the Texas Connector Project, and 

Louisiana Connector Project would impact bodies of water, including lakes, canals, rivers 

and streams. To minimize and mitigate impacts on surface waters and aquatic resources 

Port Arthur LNG proposed to utilize dry excavation methods, install a 30-inch-diameter 

pipeline to safely transport dredge material to the dredge disposal area, and install a 

shoreline protection system to prevent post-construction erosion.137 Port Arthur Pipeline 

would implement its Environmental Plan (including the Commission’s Upland Erosion 

Control, Revegetation & Maintenance Plan [Plan] and Wetland and Waterbody 

Construction and Mitigation Procedures [Procedures]) to minimize erosion and 

sedimentation resulting from the construction of the Louisiana Connector and Texas 

Connector projects. Port Arthur Pipeline proposes to utilize the horizontal directional 

drill (HDD) crossing method at 46 waterbody crossings for the Louisiana Connector 

 134 Final EIS at 5-4.

135 Final EIS at 5-4.

136 Final EIS at 5-3 – 5-4.

137 Final EIS at 5-4 – 5-5.

(continued ...)
Docket No. CP17-20-000, et al. - 41 -

Project, and at 24 crossings for the Texas Connector Project, in order to avoid impacts on

surface water resources.138 In compliance with the Commission’s Procedures, and prior 

to construction, Port Arthur Pipeline would provide Commission staff with finalized 

detailed plans for each HDD crossing and prepare final contingency plans in the event an 

HDD crossing is unsuccessful.139 Therefore, the final EIS concludes that impacts on 

water resources will be adequately minimized and are not significant.

4. Wetlands

Construction of the Liquefaction Project would affect a total of 1,661.9 acres of 

wetlands, of which 724.0 acres would be permanently filled. Port Arthur LNG would 

offset impacts on USACE jurisdictional wetlands through mitigation measures included 

in its project Compensatory Mitigation Plan. The mitigation measures include the 

beneficial reuse of over 7.8 million cubic yards of dredge material excavated from the 

ship berthing area and Pioneer Dock. The beneficial reuse of this material would create 

about 1,268.8 acres of coastal marsh wetland. Port Arthur LNG’s wetland mitigation 

would include adhering to the measures in the Commission’s Procedures, as well as Port 

Arthur LNG’s Compensatory Mitigation Plan.

Construction and operation of the Texas Connector Project and Louisiana 

Connector Project would affect about 238.1 acres and 636.9 acres of wetlands, 

respectively, of which 66.8 acres and 244.1 acres, respectively, would be permanently 

disturbed during operation of the projects. Port Arthur Pipeline would implement the 

mitigation measures outlined in its project-specific Environmental Plan (including the 

Commission’s Procedures), and will be required to comply with any mitigation measures 

identified in the USACE permit conditions for the pipeline projects. 

With the implementation of Port Arthur LNG’s and Port Arthur Pipeline’s Projectspecific plans, Port Arthur LNG’s proposed beneficial use of dredge material to restore 

emergent wetlands, the proposed mitigation measures discussed in the final EIS, the final 

EIS concludes that impacts on wetland resources will be adequately minimized and are 

not significant.

5. Vegetation

Construction and operation of the Liquefaction Project, the Texas Connector

Project, and Louisiana Connector Project would affect a total of 1,206.5 acres and 

5,767.0 acres of forested and open land vegetation types, respectively. About 845.3 acres 

 138 Final EIS at 5-6.

139 Final EIS at 5-6.

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Docket No. CP17-20-000, et al. - 42 -

of vegetation would be cleared during construction of the Liquefaction Project, and 808.0 

acres would be permanently converted to industrial use associated with operation of the 

Liquefaction Project. Additionally, 151.0 acres of open water would be created for 

operation of the Liquefaction Project.

140 Port Arthur LNG would deposit some of its 

dredged material at the J.D. Murphree wildlife management area (WMA) where it would 

be used to create coastal marshland, and revegetate other impacted areas of the WMA.141 

As a result of Port Arthur LNG’s proposed mitigation measures, including development 

of its wetland Compensatory Mitigation Plan and the beneficial reuse of dredge materials 

at J.D. Murphree WMA, the final EIS concludes that impacts on vegetation from 

construction and operation of the Liquefaction Project will be permanent but minor.

Construction of the Louisiana Connector and Texas Connector projects would 

disturb a total of 482.8 acres and 2,044.1 acres of vegetated land, respectively, including 

open and forested upland and wetland areas. Impacts on vegetation associated with 

installation of the pipelines would primarily be caused by vegetation clearing within the 

construction right-of-way and associated additional temporary work space. About 184.4 

acres of upland forest would be permanently affected along the pipeline routes. Except 

for the 410.0 acres within the permanent right-of-way that would be crossed by HDD, 

vegetation would be cleared from the entire working right-of-way.142 

No vegetation communities of special concern would be impacted by the 

Liquefaction Project or the Texas Connector Project; however, portions of the Louisiana 

Connector Project’s route crosses a Coastal Prairie community, and a stand of western 

acidic longleaf pine savannah/flatwoods.143 Port Arthur Pipeline’s Environmental Plan 

would facilitate the restoration of the Coastal Prairie community upon completion of 

construction.144 In addition, impacts on the western acidic longleaf pine 

savannah/flatwoods would be minor, as the stand is already disturbed by existing 

silviculture management, and Port Arthur Pipeline proposes to use an existing logging 

road to access the area, further reducing impacts.145 Port Arthur Pipeline would also use 

its Environmental Plan to minimize the spread of invasive aquatic species, and implement 

 140 Final EIS at 5-8.

141 Final EIS at 5-9.

142 Final EIS at 5-9.

143 Final EIS at 5-9.

144 Final EIS at 4-77.

145 Final EIS at 4-78.

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Docket No. CP17-20-000, et al. - 43 -

measures in the Commission’s Plan and Procedures to evaluate the success of 

revegetation efforts.146 Therefore, based on the minor nature of the impacts on

vegetation, and Port Arthur LNG and Port Arthur Pipeline’s proposed efforts to further 

mitigate these impacts, the final EIS concludes that the projects will not have a 

significant impact on vegetation.

6. Wildlife 

In total, approximately 7,828.1 acres of wildlife habitat would be affected by 

construction of the Liquefaction Project, and the Louisiana Connector and Texas

Connector projects. While 6,003.1 acres would be affected during operations of the 

projects, the majority of these impacts would occur at the dredge disposal areas. Overall, 

the greatest impacts would be on open wetland habitat, followed by open upland and 

forested upland habitats, which are discussed above. Due to existing industrial activity in 

the area, wildlife in the vicinity of the Liquefaction Project is anticipated to be acclimated 

to the impacts of construction and operations, particularly impacts associated with noise 

and artificial light.

147 However, Port Arthur LNG proposes several additional measures 

including directing lighting downward during construction, use of nesting inhibitors to 

discourage nesting of migratory birds near the Liquefaction Project, and utilizing ground 

flares instead of elevated flares during operation, to further minimize impacts on

migratory birds.148

Construction of the Louisiana Connector and Texas Connector projects would 

affect 2,526.5 acres of vegetated wildlife habitat, with the greatest impact on open upland 

habitat, and operation would permanently convert 816.3 acres of wildlife habitat.

149 Most 

impacts on wildlife would be limited to the duration of construction for the Louisiana 

Connector and Texas Connector projects, and abundant habitat is available for wildlife in 

the vicinity. Port Arthur Pipeline proposes to conduct surveys for bald eagle nests prior 

to construction, and to modify the construction schedule in the event a nest is located. 

Port Arthur Pipeline would implement its project-specific Environmental Plan to further 

 146 Final EIS at 5-10.

147 Final EIS at 4-86.

148 Final EIS at 5-10 – 5-11.

149 Final EIS at 5-10.

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Docket No. CP17-20-000, et al. - 44 -

minimize impacts.

150 Therefore, the final EIS determined that impacts on wildlife from 

construction and operation of the projects will not be significant.

7. Aquatic Resources

Impacts on aquatic resources from construction and operation of the Liquefaction 

Project include increased turbidity and sediment suspension, increased in-water noise, 

increased vessel traffic, and alteration of light regimes.

151 Port Arthur LNG proposes to 

minimize turbidity and sediment suspension by commencing construction from the 

landward side, working its way into the Port Arthur Canal, and would use hydraulic

dredging techniques to retain much of the entrained sediment.152 Port Arthur LNG would

also implement construction techniques that minimize noise effects on aquatic species, 

including pre-drilling pile holes, the use of a vibratory hammer, bubble curtains/

cofferdams, and gradually increasing the power and frequency of pile driving over a 

period of time, which would allow sensitive aquatic species to depart the area before 

harmful underwater sound pressures are created by the vibratory hammers. Impacts from 

increased ship traffic due to the Liquefaction Project would be mitigated by installation 

of rip-rap to reduce shoreline erosion, as well as implementation of existing U.S. Coast 

Guard ballast water requirements, among other mandatory federal requirements.153

Potential impacts on aquatic resources related to construction and operation of the 

Louisiana Connector and Texas Connector projects would be associated with increased 

erosion and sedimentation due to open-cut waterbody crossings, inadvertent release of 

drilling mud during HDD crossings, physical or chemical water alterations from 

hydrostatic testing, entrainment from water appropriation for hydrostatic testing, and any 

inadvertent spills of hazardous materials. Port Arthur Pipeline would implement the 

measures outlined in its Environmental Plan to minimize impacts on waterbodies and 

aquatic resources during pipeline construction, including reducing workspace areas near 

waterbodies, establishing buffers to prevent stormwater run-off from entering 

waterbodies, and installing erosion control devices, as well as minimizing response time 

and ensure appropriate cleanup actions are taken in the event of a spill.154 Port Arthur 

Pipeline would also implement its HDD Contingency Plan to minimize impacts in the 

 150 Final EIS at 5-11.

151 Final EIS at 5-12.

152 Final EIS at 5-11.

153 Final EIS at 5-12.

154 Final EIS at 5-12 – 5-13

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Docket No. CP17-20-000, et al. - 45 -

case of an inadvertent return of drilling mud. Once construction is complete, streambeds 

and banks would be restored to their preconstruction conditions and contours to the 

maximum extent practicable, which would aid in preventing erosion and minimize longterm impacts on aquatic resources.155

Construction and operation of the Liquefaction Project, the Texas Connector

Project, and Louisiana Connector Project would also result in temporary and permanent 

impacts on essential fish habitat (EFH). Construction and operation of the Liquefaction 

Project would affect 3.2 acres of estuarine water column and estuarine mud/soft bottom 

EFH, which would result in temporary and permanent impacts. However, the 

Liquefaction Project would create 68.3 acres of additional open water habitat for aquatic 

species and EFH-managed species by dredging the berthing area and material offloading 

facility, resulting in a net increase of estuarine mud/soft bottom and estuarine water 

column EFH.156

Construction of the Texas Connector Project would temporarily impact 1.2 acres, 

8.4 acres, and 0.8 acre of estuarine emergent marsh EFH, respectively.

157 Construction 

of the Louisiana Connector Project would temporarily affect 1,534.7 acres of EFH, 

including 131.7 acres of estuarine emergent marsh EFH and 1,403.0 acres of estuarine 

water column and mud/soft bottom EFH. Permanent access roads required for the 

operation would permanently affect 1.7 acres of EFH, 1.2 acres of estuarine emergent 

marsh, and 0.5 acre of estuarine water column and estuarine mud/soft bottom.158 Port 

Arthur LNG and Port Arthur Pipeline coordinated with the National Marine Fisheries 

Service (NMFS) on potential impacts on EFH. In an email to Commission staff on 

October 5, 2018, NMFS ultimately determined that “with the use of avoidance and 

minimization construction techniques as well as the wetlands restoration activities, the 

project would result in temporary and minimal impacts to EFH. Therefore, the EFH 

consultation required by the Magnuson-Stevens Fishery Conservation and Management 

Act is concluded and no further coordination with the NMFS is required.”159

Due to the proposed HDD crossings at over 50 locations to avoid impacts on 

waterbodies, Port Arthur Pipeline’s proposal to limit construction workspace and 

 155 Final EIS at 5-14.

156 Final EIS at 5-14.

157 Final EIS at 5-14.

158 Final EIS at 5-14 – 5-15.

159 Final EIS at 5-15. 

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Docket No. CP17-20-000, et al. - 46 -

duration at the waterbody crossings, and implementation of the proposed mitigation 

measures, the final EIS concludes that the projects would have minor and localized 

impacts on aquatic resources, including EFH.

8. Threatened, Endangered, and Other Special Status Species

According to the U.S. Fish and Wildlife Service (FWS) and NMFS, 26 federally 

listed or proposed species may occur in the counties and parishes impacted by the 

projects.160 Commission staff determined that the projects would have no effect or not be 

likely to adversely effect 25 of the 26 listed or proposed species.161 The remaining 

species, the eastern black rail (type of bird), was proposed for listing by the FWS in the 

Federal Register on October 9, 2018.

162 As required by section 7 of the Endangered 

Species Act of 1978, Commission staff requested that FWS and NMFS accept the 

information in the draft EIS as the Biological Assessment for the projects. On August 29, 

2018, NMFS provided concurrence for the species under its jurisdiction.

163 The final EIS 

reports that consultation with FWS is ongoing for the American chaffseed, and may be 

required for the eastern black rail. Environmental Condition 19 in the appendix to this 

order requires completion of Endangered Species Act consultation before construction 

may begin.

9. Land Use, Recreation, and Visual Resources

Construction of the projects would temporarily affect a total of 10,612.0 acres of 

land. Of this, approximately 2,660 acres would be allowed to revert to the existing land 

use type after the completion of construction, and approximately 7,953 acres would be 

permanently affected by the projects’ operation. The projects’ construction would 

temporarily affect a total of approximately 521 acres of agricultural land, and 

approximately 176 acres would be included in permanent right-of-way.164 The EIS states 

that agricultural land located within the pipeline permanent rights-of-way would be 

 160 Final EIS at 5-15. 

161 Final EIS at 5-15. 

162 Federal Register, 83 Fed. Reg. 50,610 (2018).

163 Final EIS at 4-131.

164 Final EIS at 5-17.

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Docket No. CP17-20-000, et al. - 47 -

restored to previous use approximately one growing season after the completion of 

construction.165 

The Louisiana Connector and Texas Connector Project’s construction workspaces 

would be located within 50 feet of 24 and 11 residential structures, respectively; the 

Liquefaction Project’s construction workspace is not within 50 feet of any residential 

structures.166 The draft EIS and final EIS included site-specific plans for residential 

structures within 25 feet of the construction workspaces. No comments were received 

from landowners regarding these site-specific plans. 

Construction of the projects would occur near several recreation areas, including 

the J.D. Murphree WMA, Round Lake, Keith Lake, and private hunting grounds.167 

Generally speaking, however, impacts on recreation areas would be temporary and 

limited to the duration of construction – which would extend from several days to several 

weeks depending on the area of construction.168

The Liquefaction Project includes many aboveground structures that could result 

in a visual resource impact, including three LNG storage tanks that would be

approximately 256 feet tall, liquefaction trains, and additional infrastructure, most of 

which would require lighting. The Liquefaction Project would be sited along the Port 

Arthur Canal, which would create a strong vertical visual contrast across a relatively flat 

existing landscape.169 The ship berths, offloading facilities, and utility buildings would 

also alter the existing viewshed. The storage tanks and liquefaction facilities would not 

be screened and would result in permanent visual impacts on views from the eastern edge 

of the nearby J.D. Murphree WMA. Impacts on views for those traveling on State 

Highway 87 and State Highway 82, visiting Pleasure Island or the Port Arthur Canal, 

boaters in the waterway, and viewers from a variety of recreational locations would be 

relatively minor due to existing industrial facilities surrounding and northeast of the 

project area.170 Port Arthur LNG would restrict any permanent lighting needed for the 

Liquefaction Project terminal facilities to the property boundaries and direct the 

 165 Final EIS at 5-17.

166 Final EIS at 5-16.

167 Final EIS at 5-17.

168 Final EIS at 5-17.

169 Final EIS at ES-7.

170 Final EIS at ES-7.

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Docket No. CP17-20-000, et al. - 48 -

permanent lighting downward towards these sites.171 The EIS concluded that because of 

the existing commercial, industrial, and developed nature of the area, including the 

existing Golden Pass liquefaction terminal within 3 miles of the proposed Liquefaction 

Project, impacts from facility siting and its lighting will be consistent with the area. The 

final EIS therefore concludes that land use, recreation, and visual resource impacts 

associated with the projects would be minor.

10. Socioeconomics

As stated in the EIS, construction of the projects would result in minor positive 

socioeconomic impacts from employment, and not have a significant adverse impact on 

local populations, employment, provision of community services, or property values.172 

Additionally, there would not be any disproportionately high or adverse environmental 

and human health impacts on low-income and minority populations.173 Construction of 

the projects would result in minor, temporary impacts on local transportation 

infrastructure and traffic. Environmental Condition 23 in the appendix to this order 

requires Port Arthur LNG to file a Transportation Plan to outline how it would manage 

access to and from the Liquefaction Project construction site by personnel, equipment, 

and deliveries on a daily basis.

11. Cultural Resources

Commission staff is currently in the process of complying with section 106 of the 

National Historic Preservation Act for all projects.174 Therefore, Environmental 

Condition 25 requires section 106 consultation be completed for all Project elements 

before Port Arthur LNG and Port Arthur Pipeline may commence construction. In 

addition, Commission staff, as well as staff from Port Arthur Pipeline have met with the 

Coushatta Tribe of Louisiana to address their concerns over the Louisiana Connector 

Project’s potential impacts on cultural resources.175 On November 15, 2018, the 

Coushatta Tribe filed a letter concurring with a determination that no historic properties 

would be affected by the Louisiana Connector Project; and Commission staff, Port Arthur 

 171 Final EIS at ES-7.

172 Final EIS at 5-19 – 5-21.

173 Final EIS at 5-21.

174 Final EIS at 5-23.

175 Final EIS at 5-23 – 5-24.

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Docket No. CP17-20-000, et al. - 49 -

Pipeline, and the Coushatta Tribe continue to work together to address the Tribe’s 

cultural resource concerns. 

12. Air Quality and Noise

Construction emissions for the Liquefaction Project are estimated for 

approximately 60 months. Construction emissions would not be a permanent source, 

and, therefore, not have a long-term effect on air quality in the area.176 Most

construction-related emissions from the Louisiana Connector and Texas Connector projects

would be temporary and localized and would dissipate with time and distance from areas 

of active construction. Further, construction emissions along the pipelines would subside 

once construction is complete.177

Long-term impacts on air quality would result from operation of the Liquefaction

Project facilities and the pipeline compressor stations. Port Arthur LNG and Port Arthur 

Pipeline would minimize potential impacts on air quality caused by operation of the 

liquefaction facilities and compressor stations by adhering to applicable federal and state 

regulations and installing best available control technology to minimize emissions.178

Therefore, with the mitigation measures that Port Arthur LNG and Port Arthur Pipeline

have proposed, the final EIS concludes that there would be no regionally significant 

impacts on air quality.179

Noise would be generated during construction of the projects. Noise levels would 

be highest in the immediate vicinity of construction activities and would diminish with 

distance from the work area.180 These impacts would be localized and temporary.

Construction would generally not affect nighttime noise levels as it would be limited to 7

a.m. to 10 p.m., except for pile driving, HDD activities, and specific construction activities 

such as tie-ins and hydrostatic testing.

181 For construction of the Liquefaction Project, 

the City of Port Arthur’s noise standard for the noise sensitive areas (NSA) in residential 

areas would limit project-generated noise to no greater than 57 A-weighted decibels

 176 Final EIS at 5-22 – 5-23.

177 Final EIS at 4-239.

178 Final EIS at ES-7.

179 Final EIS at ES-7.

180 Final EIS at 4-248.

181 Final EIS at 4-248.

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Docket No. CP17-20-000, et al. - 50 -

(dBA) during the day (7 a.m. to 10 p.m.) and 52 dBA at night (10 p.m. to 7 a.m.); 

however, construction-related noise is exempt from this standard provided that such 

activities do not take place during nighttime hours.182

During construction of the Louisiana Connector and Texas Connector projects, use 

of the HDD method would result in minor impacts on NSAs in the vicinity of the drilling 

equipment. Therefore, Environmental Condition 26 in the appendix to this order requires 

Port Arthur Pipeline, prior to the use of HDDs at locations where HDD-related noise 

could exceed Commission sound level criteria at NSAs, to file HDD noise mitigation 

plans.

Operation of the Liquefaction Project and the Texas Connector Project’s South 

Compressor Station (located near the Liquefaction Project) would generate sound levels 

throughout the life of the projects, but the increase in noise levels would be below the 

“barely detectable” noise level increase of 3 dBA, and would be below the FERC limit

standard of a day-night sound level (Ldn) of 55 dBA, resulting in only minor impacts on 

the nearest NSA.183 Further, Environmental Condition 27 requires Port Arthur LNG to 

file a full-load noise survey no later than 60 days after each liquefaction train is put in 

service for the first and second liquefaction trains. Environmental Condition 27 also 

requires that if noise levels attributable to operation of the Liquefaction Project and South 

Compressor Station exceed the FERC limit of 55 dBA Ldn, Port Arthur LNG must reduce 

the facilities’ noise contribution to result in a noise level that is no higher than the FERC 

standard. Environmental Condition 28 also requires Port Arthur LNG to file a full-load

noise survey no later than 60 days after placing all the Liquefaction Project facilities and 

South Compressor Station in service. 

Sound levels would increase during operation of the Texas Connector Project’s

North Compressor Station, the Louisiana Connector Project’s compressor station, and the 

meter stations associated with the pipeline projects, which would occur for the life of the

Louisiana Connector and Texas Connector projects. To reduce noise impacts, Port 

Arthur Pipeline would implement mitigation measures such as the use of acoustically 

treated compressor enclosures, silencers on the exhaust outlet and air intake, and 

acoustically treated wall and roof fan openings.184 Based on Commission staff’s noise 

analysis as reported in the final EIS, the predicted noise levels attributable to operation of 

the Texas Connector Project’s North Compressor Station, the Louisiana Connector 

Project’s compressor station, and the meter stations would be less than 55 dBA Ldn at all 

 182 Final EIS at 4-248 – 4-249.

183 Final EIS at 4-249 at 5-24.

184 Final EIS at 5-24.

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Docket No. CP17-20-000, et al. - 51 -

nearby NSAs.

185 To ensure that noise levels would be below 55 dBA Ldn, Environmental 

Condition 29 requires Port Arthur Pipeline to file noise surveys during full-load operations

and, if the noise levels exceed the FERC standard, that Port Arthur Pipeline install

additional noise controls to meet the FERC standard within 1 year of the in-service date. 

The final EIS concludes that any increase in noise levels during construction and 

operation of the Liquefaction Project, Louisiana Connector Project, and Texas Connector

Project would be minor and not result in significant impacts.

13. Reliability and Safety

Commission staff conducted a preliminary engineering and technical review of the 

Liquefaction Project, including potential external impacts based on the site location. 

Based on this review, the final EIS recommends a number of mitigation measures for 

implementation prior to initial site preparation, prior to construction of final design, prior 

to commissioning, prior to introduction of hazardous fluids, prior to commencement of 

service, and throughout life of the facility, to enhance the reliability and safety of the

facility. These recommendations have been adopted as mandatory conditions in the 

appendix to this order. On September 11, 2015, the U.S. Coast Guard issued a Letter of 

Recommendation to the Commission indicating the Sabine Neches River Ship Channel 

would be considered suitable for accommodating the type and frequency of LNG marine 

traffic associated with the Liquefaction Project. If the LNG Facility is authorized and 

constructed, the facility would be subject to the USCG’s inspection and enforcement 

program to ensure compliance with the requirements of 33 CFR 105 and 33 CFR 127. 

Based on Commission staff’s external impact analysis and preliminary evaluation of the 

engineering design, and with the incorporation of these recommended mitigation measures

and oversight, the final EIS concludesthat the Liquefaction Project’s design would include 

acceptable layers of protection or safeguards that would reduce the risk of a potentially 

hazardous scenario from developing into an event that could impact the offsite public.

Further, as noted above,186 PHMSA determined that the siting of the proposed 

LNG facilities complies with the federal safety standards governing the location, design, 

construction, operation, and maintenance of LNG facilities. The PHMSA LOD 

summarizes PHMSA’s evaluation of the hazard modeling results and endpoints used to 

establish exclusion zones, as well as its review of Port Arthur LNG’s evaluation of 

potential incidents and safety measures that could have a bearing on the safety of plant 

personnel and the surrounding public. 

 185 Id. at 4-249.

186 See supra at P 26.

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Docket No. CP17-20-000, et al. - 52 -

Port Arthur Pipeline must design, construct, operate, and maintain its proposed 

pipelines and aboveground facilities in accordance with the DOT Minimum Federal 

Safety Standards.

187 These regulations, which are intended to protect the public and to 

prevent natural gas facility accidents and failures, include specifications for material

selection and qualification, minimum design requirements, and protection of pipelines 

from corrosion. Accordingly, the final EIS concludes that Port Arthur Pipeline’s 

compliance with the DOT’s safety standards will ensure that Port Arthur Pipeline’s

construction and operation of the facilities would not have a significant impact on public

safety.188

14. Greenhouse Gas Emissions

With respect to impacts from GHGs, the final EIS discusses the direct GHG 

impacts from construction and operation of the projects, the climate change impacts in 

the region,189 and the regulatory structure for GHGs under the Clean Air Act.190 

The final EIS estimated that operation of the Liquefaction Project and the 

Louisiana Connector and Texas Connector project’s compressor stations may result in 

emissions of up to 4,722,648 metric tons per year of carbon dioxide equivalent (CO2e).191 

To provide context to the direct GHG estimate, according to the national net CO2e 

emissions estimate in the EPA’s Inventory of U.S. Greenhouse Gas Emissions and Sinks 

(EPA 2018), 5.8 billion metric tons of CO2e were emitted at the national level in 2016 

(inclusive of CO2e sources and sinks). The direct and indirect operational emissions of 

the LNG terminal could potentially increase CO2e emissions based on the 2016 levels by 

 187 49 C.F.R. § 192 (2018).

188 Final EIS at 4-312.

189 Final EIS at 4-360 – 4-362.

190 Final EIS at 4-228 and 4-231. 

191 Final EIS at Tables 4.11.1-7. CO2e emissions in the final EIS are expressed in 

short tons, which have been converted to metric tons in this Order so the emissions may 

be viewed in context with the EPA’s Inventory of U.S. Greenhouse Gas Emissions and 

Sinks.

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Docket No. CP17-20-000, et al. - 53 -

approximately 0.08 percent at the national level.192 Currently, there are no national 

targets to use as benchmarks for comparison.193 

The Final EIS included a qualitative discussion that addressed various effects of 

climate change.194 The Final EIS acknowledges that the quantified GHG emissions from 

the construction and operation of the project will contribute incrementally to climate 

change.195 Further, the Commission has previously concluded it could not determine a 

project’s incremental physical impacts on the environment caused by GHG emissions.196 

The Commission has also previously concluded it could not determine whether a 

project’s contribution to climate change would be significant.197

15. Cumulative Impacts

The final EIS considered the cumulative impacts of the projects with other projects 

or actions within the geographic and temporal scope of the projects.198 The types of other 

projects evaluated in the final EIS that could potentially contribute to cumulative impacts 

on a range of environmental resources include existing LNG terminals and future 

liquefaction projects, oil and gas facilities, other industrial facilities, utility and 

transportation projects, commercial and residential developments, and government 

facilities/activities.199 The final EIS concludes that the project’s contribution to 

cumulative impacts on resources affected by the projects would not be significant, and 

 192 EPA, Inventory of U.S. Greenhouse Gas Emissions and Sinks 1990-2016

(2018), https://www.epa.gov/sites/production/files/2018-

1/documents/2018_complete_report.pdf. 

193 The national emissions reduction targets expressed in the EPA’s Clean Power 

Plan and the Paris climate accord are pending repeal and withdrawal, respectively. 

194 Final EIS at 4-360 – 4-362.

195 Final EIS at 4-361. 

196 Dominion Transmission, Inc., 163 FERC ¶ 61,128, at PP 67-70 (2018) 

(LaFleur, Comm’r, dissenting in part; Glick, Comm’r, dissenting in part). 

197 Id.

198 Final EIS at 4-324.

199 Final EIS at 5-25.

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Docket No. CP17-20-000, et al. - 54 -

that the potential cumulative impacts of the projects and the other projects considered 

would be minor or insignificant.200

16. Alternatives

The EIS assessed the No-Action Alternative, 20 new LNG or LNG terminal 

expansion system alternatives, 3 site alternatives, and various facility configuration 

alternatives for the Liquefaction Project that could achieve the Liquefaction Project’s 

objectives. In addition, three pipeline route alternatives were considered. Alternatives 

were evaluated and compared to the projects to determine whether the alternatives were 

technically and economically feasible and practical; and offer a significant environmental 

advantage over the proposed projects. The final EIS concludes that the alternatives 

proposed did not offer a significant environmental advantage and found that the proposed 

projects, as modified by Commission staff’s recommended mitigation measures, which 

are attached as conditions to the appendix to this order, was the preferred alternative.201

17. Environmental Analysis Conclusion

We have reviewed the information and analysis contained in the final EIS 

regarding potential environmental effects of the projects, as well as other information in 

the record. We are adopting the environmental recommendations in the final EIS and 

include them as conditions in the appendix to this order. Compliance with the 

environmental conditions appended to our orders is integral to ensuring that the 

environmental impacts of approved projects are consistent with those anticipated by our 

environmental analyses. Thus, Commission staff carefully reviews all information 

submitted. Commission staff will only issue a construction notice to proceed with an 

activity when satisfied that the applicant has complied with all applicable conditions. We 

also note that the Commission has the authority to take whatever steps are necessary to 

ensure the protection of environmental resources during construction and operation of the 

projects, including authority to impose any additional measures deemed necessary to 

ensure continued compliance with the intent of the conditions of the order, as well as the 

avoidance or mitigation of unforeseen adverse environmental impacts resulting from 

project construction and operation.

We agree with the conclusions presented in the final EIS and find that the projects, 

if constructed and operated as described in the final EIS, is an environmentally acceptable 

action. Further, for the reasons discussed throughout the order, as stated above, we find 

that the Liquefaction Project is not inconsistent with the public convenience and 

 200 Final EIS at ES-9.

201 Final EIS at ES-9 – ES-10.
Docket No. CP17-20-000, et al. - 55 -

necessity, and that the Louisiana Connector and Texas Connector projects are in the 

public convenience and necessity.

Any state or local permits issued with respect to the jurisdictional facilities 

authorized herein must be consistent with the conditions of this authorization and 

Certificate. The Commission encourages cooperation between jurisdictional companies

and local authorities. However, this does not mean that state and local agencies, through 

application of state or local laws, may prohibit or unreasonably delay the construction or 

operation of facilities approved by this Commission.202

VI. Conclusion

At a hearing held on April 18, 2019, the Commission on its own motion received 

and made a part of the record in this proceeding all evidence, including the application, 

and exhibits thereto, and all comments, and upon consideration of the record,

The Commission orders:

(A) In Docket No. CP17-20-000, Port Arthur LNG is authorized under section 

3 of the NGA to site, construct, and operate the proposed project located in Port Arthur, 

Texas, as described and conditioned herein, and as fully described in Port Arthur LNG’s 

application and subsequent filings, including any commitments made therein, and subject 

to the environmental conditions contained in the appendix of this order.

(B) Port Arthur LNG’s proposed project shall be constructed and made 

available for service within five years of the date of this order.

(C) In Docket Nos. CP17-21-000, CP17-21-001, and CP18-7-000, a certificate 

of public convenience and necessity is issued to Port Arthur Pipeline authorizing it to 

construct and operate the Texas and Louisiana Connector projects, as described and 

conditioned herein, and as more fully described in the applications and subsequent filings 

by the application, including any commitments made therein.

 202 See 15 U.S.C. § 717r(d) (state or federal agency’s failure to act on a permit 

considered to be inconsistent with Federal law); see also Schneidewind v. ANR Pipeline 

Co., 485 U.S. 293, 310 (1988) (state regulation that interferes with FERC’s regulatory 

authority over the transportation of natural gas is preempted) and Dominion 

Transmission, Inc. v. Summers, 723 F.3d 238, 245 (D.C. Cir. 2013) (noting that state and 

local regulation is preempted by the NGA to the extent it conflicts with federal 

regulation, or would delay the construction and operation of facilities approved by the 

Commission).
Docket No. CP17-20-000, et al. - 56 -

(D) The certificate authority issued in Ordering Paragraph (C) is conditioned 

on: 

a. Port Arthur Pipeline’s completing the authorized construction of the 

proposed facilities and making them available for service within five years 

of the date of this order pursuant to section 157.20(b) of the Commission’s 

regulations;

b. Port Arthur Pipeline’s compliance with all applicable Commission 

regulations, including, but not limited to, Parts 154, 157, and 284, and 

paragraphs (a), (c), (e), and (f) of section 157.20 of the Commission’s 

regulations; 

c. Port Arthur Pipeline’s compliance with the environmental conditions in the 

appendix to this order, and

d. Port Arthur Pipeline filing a written statement affirming that it has executed 

firm contracts for the capacity levels and terms of service represented in 

signed precedent agreements, prior to commencing construction.

(E) A blanket construction certificate is issued to Port Arthur Pipeline under 

Subpart F of Part 157 of the Commission’s regulations.

(F) A blanket transportation certificate is issued to Port Arthur Pipeline under 

Subpart G of Part 284 of the Commission’s regulations.

(G) Port Arthur Pipeline’s initial rates and tariff are approved, as conditioned 

and modified in this order.

(H) Port Arthur Pipeline shall file actual tariff records that comply with the 

requirements contained in the body of this order not less than 60 days prior to the 

commencement of interstate service consistent with Part 154 of the Commission’s 

regulations.

(I) No later than three months after the end of its first three years of actual 

operation, as discussed herein, Port Arthur Pipeline must make a filing to justify its 

existing cost-based firm and interruptible recourse rates. Port Arthur Pipeline’s cost and 

revenue study should be filed through the eTariff portal using a Type of Filing Code 580. 

In addition, Port Arthur Pipeline is advised to include as part of the eFiling description, a 
Docket No. CP17-20-000, et al. - 57 -

reference to Docket Nos. CP17-21-000, CP17-21-001, and CP18-7-000, and to the cost 

and revenue study.203

(J) Port Arthur LNG and Port Arthur Pipeline shall notify the Commission’s 

environmental staff by telephone, e-mail, and/or facsimile of any environmental 

noncompliance identified by other federal, state, or local agencies on the same day that 

such agency notifies Port Arthur LNG or Port Arthur Pipeline. Port Arthur LNG and Port 

Arthur Pipeline shall file written confirmation of such notification with the Secretary of 

the Commission within 24 hours.

By the Commission. Commissioner LaFleur is concurring with a separate statement 

attached.

Commissioner Glick is dissenting with a separate statement 

attached.

( S E A L )

Nathaniel J. Davis, Sr.,

Deputy Secretary.

 203 Electronic Tariff Filings, 130 FERC ¶ 61,047 at P 17. 
Docket No. CP17-20-000, et al. - 58 -

Appendix A

Environmental Conditions

As recommended in the final environmental impact statement and otherwise amended 

herein, this authorization includes the following conditions:

1. Port Arthur LNG and Port Arthur Pipeline shall follow the construction procedures 

and mitigation measures described in its application and supplements (including 

responses to staff data requests) and as identified in the final environmental impact 

statement (EIS), unless modified by the Order. Port Arthur LNG and Port Arthur 

Pipeline must:

a. request any modification to these procedures, measures, or conditions in a 

filing with the Secretary of the Commission (Secretary);

b. justify each modification relative to site-specific conditions;

c. explain how that modification provides an equal or greater level of 

environmental protection than the original measure; and

d. receive approval in writing from the Director of the Office of Energy Projects 

(OEP) before using that modification.

2. For the Liquefaction Project, the Director of OEP, or the Director’s designee, has 

delegated authority to address any requests for approvals or authorizations 

necessary to carry out the conditions of the Order, and take whatever steps are 

necessary to ensure the protection of life, health, property, and the environment 

during construction and operation of the project. This authority shall allow:

a. the modification of conditions of the Order; 

b. stop-work authority and authority to cease operation; and

c. the imposition of any additional measures deemed necessary to ensure 

continued compliance with the intent of the conditions of the Order as well 

as the avoidance or mitigation of unforeseen adverse environmental impact 

resulting from project construction and operation. 

3. For the pipeline facilities, the Director of OEP, or the Director’s designee, has 

delegated authority to address any requests for approvals or authorizations 

necessary to carry out the conditions of the Order, and take whatever steps are 
Docket No. CP17-20-000, et al. - 59 -

necessary to ensure the protection of environmental resources during construction 

and operation of the projects. This authority shall allow:

a. the modification of conditions of the Order; 

b. stop-work authority and authority to cease operation; and

c. the imposition of any additional measures deemed necessary to ensure 

continued compliance with the intent of the conditions of the Order as well 

as the avoidance or mitigation of unforeseen adverse environmental impact 

resulting from project construction and operation. 

4. Prior to any construction, Port Arthur LNG and Port Arthur Pipeline shall file 

affirmative statements with the Secretary, certified by a senior company official, 

that all company personnel, Environmental Inspectors (EI), and contractor 

personnel will be informed of the EIs’ authority and have been or will be trained on 

the implementation of the environmental mitigation measures appropriate to their 

jobs before becoming involved with construction and restoration activities.

5. The authorized facility locations shall be as shown in the EIS, as supplemented by 

filed alignment sheets. As soon as they are available and before the start of 

construction, Port Arthur LNG and Port Arthur Pipeline shall file with the 

Secretary any revised detailed survey alignment maps/sheets at a scale not smaller 

than 1:6,000 with station positions for all facilities approved by the Order. All 

requests for modifications of environmental conditions of the Order or site-specific 

clearances must be written and must reference locations designated on these 

alignment maps/sheets.

Port Arthur Pipeline’s exercise of eminent domain authority granted under Natural 

Gas Act (NGA) section 7(h) in any condemnation proceedings related to the Order 

must be consistent with these authorized facilities and locations. Port Arthur 

Pipeline’s right of eminent domain granted under NGA section 7(h) does not 

authorize it to increase the size of its natural gas pipelines or facilities to 

accommodate future needs or to acquire a right-of-way for a pipeline to transport a 

commodity other than natural gas.

6. Port Arthur LNG and Port Arthur Pipeline shall file with the Secretary detailed 

alignment maps/sheets and aerial photographs at a scale not smaller than 1:6,000 

identifying all route realignments or facility relocations; staging areas; pipe storage 

yards; new access roads; and other areas that will be used or disturbed and have not 

been previously identified in filings with the Secretary. Approval for each of these 

areas must be explicitly requested in writing. For each area, the request must include 

a description of the existing land use/cover type, documentation of landowner 

approval, whether any cultural resources or federally-listed threatened or 
Docket No. CP17-20-000, et al. - 60 -

endangered species will be affected, and whether any other environmentally 

sensitive areas are within or abutting the area. All areas shall be clearly identified 

on the maps/sheets/aerial photographs. Each area must be approved in writing by 

the Director of OEP before construction in or near that area.

This requirement does not apply to extra workspace allowed by the Commission’s 

Upland Erosion Control, Revegetation & Maintenance Plan and/or minor field 

realignments per landowner needs and requirements that do not affect other 

landowners or sensitive environmental areas such as wetlands.

Examples of alterations requiring approval include all route realignments and 

facility location changes resulting from:

a. implementation of cultural resources mitigation measures;

b. implementation of endangered, threatened, or special concern species 

mitigation measures;

c. recommendations by state regulatory authorities; and

d. agreements with individual landowners that affect other landowners or could 

affect sensitive environmental areas.

7. Within 60 days of the acceptance of the authorization and before construction 

begins, Port Arthur LNG and Port Arthur Pipeline shall each file Implementation 

Plans with the Secretary for review and written approval by the Director of OEP. 

Port Arthur LNG and Port Arthur Pipeline must file revisions to their plans as 

schedules change. The plans shall identify:

a. how Port Arthur LNG and Port Arthur Pipeline will implement the 

construction procedures and mitigation measures described in its application 

and supplements (including responses to staff data requests), identified in the 

EIS, and required by the Order;

b. how Port Arthur LNG and Port Arthur Pipeline will incorporate these 

requirements into the contract bid documents, construction contracts 

(especially penalty clauses and specifications), and construction drawings so 

that the mitigation required at each site is clear to on-site construction and 

inspection personnel;

c. the number of EIs assigned per spread and how Port Arthur LNG and Port 

Arthur Pipeline will ensure that sufficient personnel are available to 

implement the environmental mitigation;
Docket No. CP17-20-000, et al. - 61 -

d. the number of company personnel, including EIs and contractors, who will

receive copies of the appropriate material;

e. the location and dates of the environmental compliance training and 

instructions Port Arthur LNG and Port Arthur Pipeline will give to all 

personnel involved with construction and restoration (initial and refresher 

training as the projects progress and personnel change), with the opportunity 

for OEP staff to participate in the training session(s);

f. the company personnel (if known) and specific portion of the Port Arthur 

LNG’s and Port Arthur Pipeline’s organization having responsibility for 

compliance;

g. the procedures (including use of contract penalties) Port Arthur LNG and 

Port Arthur Pipeline will follow if noncompliance occurs; and

h. for each discrete facility, a Gantt or PERT chart (or similar project scheduling 

diagram) and dates for:

i. the completion of all required surveys and reports;

ii. the environmental compliance training of on-site personnel;

iii. the start of construction; and

iv. the start and completion of restoration.

8. Port Arthur LNG and Port Arthur Pipeline shall employ a team of EIs, including at 

least one EI for the Liquefaction Project, and at least one EI per construction spread

for the pipeline facilities. The EI(s) shall be:

a. responsible for monitoring and ensuring compliance with all mitigation 

measures required by the Order and other grants, permits, certificates, or 

other authorizing documents;

b. responsible for evaluating the construction contractor’s implementation of 

the environmental mitigation measures required in the contract (see condition 

7) and any other authorizing document;

c. empowered to order correction of acts that violate the environmental 

conditions of the Order, and any other authorizing document;

d. a full-time position, separate from all other activity inspectors;

e. responsible for documenting compliance with the environmental conditions 

of the Order, as well as any environmental conditions/permit requirements 
Docket No. CP17-20-000, et al. - 62 -

imposed by other federal, state, or local agencies or the Coushatta Tribe of 

Louisiana for Tribal Trust Lands; and

f. responsible for maintaining status reports.

9. Beginning with the filing of their respective Implementation Plans, Port Arthur 

LNG and Port Arthur Pipeline shall each file updated status reports with the 

Secretary on a monthly basis for the Liquefaction Project and weekly basis for the 

Louisiana Connector and Texas Connector projects until all construction and 

restoration activities are complete. Problems of a significant magnitude shall be 

reported to the FERC within 24 hours. On request, these status reports will also be 

provided to other federal and state agencies with permitting responsibilities. Status 

reports shall include:

a. an update on Port Arthur LNG’s and Port Arthur Pipeline’s efforts to obtain 

the necessary federal authorizations;

b. the construction status of Liquefaction Facilities and each spread of the 

Louisiana Connector and Texas Connector projects, work planned for the 

following reporting period, and any schedule changes for stream crossings 

or work in other environmentally sensitive areas;

c. a listing of all problems encountered, contractor nonconformance/deficiency 

logs, and each instance of noncompliance observed by the EIs during the 

reporting period (both for the conditions imposed by the Commission and 

any environmental conditions/permit requirements imposed by other federal, 

state, or local agencies);

d. a description of the corrective and remedial actions implemented in response 

to all instances of noncompliance, nonconformance, or deficiency;

e. the effectiveness of all corrective and remedial actions implemented;

f. a description of any landowner/resident complaints that may relate to 

compliance with the requirements of the Order, and the measures taken to 

satisfy their concerns; and

g. copies of any correspondence received by Port Arthur LNG and Port Arthur 

Pipeline from other federal, state, local, or tribal permitting agencies 

concerning instances of noncompliance, and the Port Arthur LNG’s and Port 

Arthur Pipeline’s responses.

10. Port Arthur LNG and Port Arthur Pipeline must receive written authorization from 

the Director of OEP before commencing construction of any project facilities. 

To obtain such authorization, Port Arthur LNG and Port Arthur Pipeline shall file 
Docket No. CP17-20-000, et al. - 63 -

with the Secretary documentation that it has received all applicable authorizations 

required under federal law (or evidence of waiver thereof).

11. Port Arthur LNG must receive written authorization from the Director of OEP prior 

to introducing hazardous fluids into the liquefaction facilities. Instrumentation 

and controls, hazard detection, hazard control, and security components/systems 

necessary for the safe introduction of such fluids shall be installed and functional.

12. Port Arthur LNG must receive written authorization from the Director of OEP 

before placing the Liquefaction Project facilities into service. Such 

authorization will only be granted following a determination that the facilities have 

been constructed in accordance with the FERC approval, can be expected to operate 

safely as designed, and the rehabilitation and restoration of the area affected by the 

Liquefaction Project facilities are proceeding satisfactorily. 

13. Port Arthur Pipeline must receive written authorization from the Director of OEP 

before placing the Texas Connector and/or the Louisiana Connector projects

into service. Such authorization will only be granted following a determination that 

the rehabilitation and restoration of the right-of-way and other areas affected by the 

Louisiana Connector and Texas Connector projects are proceeding satisfactorily. 

14. Within 30 days of placing the authorized facilities in service, Port Arthur LNG

and Port Arthur Pipeline shall file an affirmative statement with the Secretary, 

certified by a senior company official:

a. that the facilities have been constructed in compliance with all applicable 

conditions, and that continuing activities will be consistent with all 

applicable conditions; or

b. identifying which of the conditions in the Order Port Arthur LNG and Port 

Arthur Pipeline have complied with or will comply with. This statement 

shall also identify any areas affected by the projects where compliance 

measures were not properly implemented, if not previously identified in filed 

status reports, and the reason for noncompliance.

15. Prior to construction of the projects, Port Arthur LNG and Port Arthur Pipeline

each shall file with the Secretary, for review and written approval by the Director 

of OEP, a project-specific plan for construction near known abandoned oil and gas 

wells. This plan shall identify actions to be taken if any unidentified oil or gas wells 

are discovered during construction and discuss how Port Arthur LNG or Port Arthur 

Pipeline will maintain the integrity of any plugged wells. (section 4.1.2)

16. Prior to construction of the compressor stations associated with the Louisiana 

Connector and Texas Connector projects, Port Arthur Pipeline shall file with the 
Docket No. CP17-20-000, et al. - 64 -

Secretary the results of geotechnical studies for the compressor stations, including 

any recommended mitigation measures Port Arthur Pipeline will adopt as part of 

the final engineering design. (section 4.1.3.1)

17. Prior to construction of the Liquefaction Project, Port Arthur LNG shall provide 

the U.S. Environmental Protection Agency, U.S. Army Corps of Engineers 

(USACE), Texas Commission on Environmental Quality, and Texas Railroad 

Commission with the soil and sediment analysis conducted at the area within the 

ship canal at the marine berth, construction dock, material offloading facility, and 

landward component of the material offloading facility for review. Port Arthur 

LNG shall file the conclusions of the agency reviews with the Secretary along with 

documentation of its consultations with these agencies including any measures Port 

Arthur LNG will need to adopt if the analysis discovers previously unknown 

contamination. (section 4.2.1.6)

18. Prior to construction of the Louisiana Connector and Texas Connector

projects, Port Arthur Pipeline shall file with the Secretary, for review and approval

by the Director of OEP, the anticipated volume and source of water to be used for 

dust control. (section 4.3.2.2)

19. Port Arthur LNG and Port Arthur Pipeline shall not begin construction of the 

projects until:

a. all outstanding biological surveys are completed;

b. the FERC staff complete any necessary Endangered Species Act section 7 

consultation, including conference for the eastern black rail, with the U.S. 

Fish and Wildlife Service;

c. Port Arthur LNG and Port Arthur Pipeline have received written notification 

from the Director of OEP that construction and/or use of mitigation 

(including implementation of conservation measures) may begin. (section 

4.7.3)

20. Prior to construction of the Louisiana Connector Project, Port Arthur Pipeline

shall conduct surveys for the American chaffseed on the remaining no-access 

parcels with potential habitat. If the American chaffseed is found, Port Arthur 

Pipeline shall incorporate methods to avoid impacts on the American chaffseed. 

Port Arthur Pipeline shall file with the Secretary and the U.S. Fish and Wildlife 

Service (Louisiana office) both the survey results and Port Arthur Pipeline’s

proposed avoidance methods. (section 4.7.3.5)

21. Prior to construction of the Liquefaction Project, Port Arthur LNG shall file with 

the Secretary documentation of concurrence from the USACE and Texas General 
Docket No. CP17-20-000, et al. - 65 -

Land Office that the Liquefaction Project is consistent with the Coastal Zone 

Management Act. (section 4.8.9.1)

22. Prior to construction of the Louisiana Connector and Texas Connector

projects, Port Arthur Pipeline shall file with the Secretary documentation of 

concurrence from the USACE, Texas General Land Office, and Louisiana Office of 

Coastal Management that the Texas Connector Project and Louisiana Connector 

Project are consistent with the Coastal Zone Management Act. (section 4.8.9.2)

23. Prior to construction of the Liquefaction Project, Port Arthur LNG shall file with 

the Secretary its Transportation Plan for the Liquefaction Project, for review and 

written approval by the Director of OEP. The plan shall include personnel training; 

permitting requirements; consultations conducted with local and state agencies; and 

how access to/from the work site by personnel, equipment, and materials will be 

managed on a daily basis throughout construction. (section 4.9.6.1)

24. Prior to construction of the Louisiana Connector Project in Louisiana, Port 

Arthur Pipeline shall file with the Secretary, for review and written approval by the 

Director of OEP, a revised Unanticipated Discoveries Plan that clarifies that Tribal 

Historic Preservation Office construction recommencement authorization is only 

applicable to Coushatta Tribe of Louisiana tribal trust lands. (section 4.10.2)

25. Port Arthur LNG and Port Arthur Pipeline shall not begin construction of facilities 

and/or use of staging, storage, or temporary work areas and new or to-be-improved 

access roads associated with the projects until:

a. Port Arthur LNG files with the Secretary, the outstanding information for 

Dredge Disposal Area 8, and the Texas State Historic Preservation Office’s 

(SHPO) comments on the information;

b. Port Arthur LNG files any required survey report for Dredge Disposal Area 

8, and the Texas SHPO’s comments on the report;

c. Port Arthur Pipeline files with the Secretary all outstanding survey reports, 

evaluation reports, special studies, and any required avoidance/treatment 

plans, and the Texas and Louisiana SHPOs’ and the Coushatta Tribe of

Louisiana Tribal Historic Preservation Office’s comments (as applicable) on 

these; 

d. the Advisory Council on Historic Preservation is afforded an opportunity to 

comment if historic properties will be adversely affected; and

e. the FERC staff reviews and the Director of OEP approves the cultural 

resources reports, studies, and plans, and notifies Port Arthur LNG and Port 

Arthur Pipeline in writing that treatment plans/mitigation measures 
Docket No. CP17-20-000, et al. - 66 -

(including archaeological data recovery) may be implemented and/or 

construction may proceed.

All materials filed with the Commission containing location, character, 

and ownership information about cultural resources must have the cover and any 

relevant pages therein clearly labeled in bold lettering “CUI//PRIV – DO NOT 

RELEASE.”(sections 4.10.4.1. and 4.10.4.2)

26. Prior to construction of horizontal directional drills (HDD) at mileposts (MP)

19.6 and 20.3 along the Texas Connector Project’s Northern Pipeline; MP 0.5 

along the GTS Lateral; MP 0.8 along the FGT Lateral; and MPs 38.7, 40.5, 

42.5, 47.9, 48.5, 56.8, 60.2, 79.4, 91.1, 96.9, 110.1, and 110.3 along the Louisiana 

Connector Project where HDD-related noise could exceed the Commission’s 

sound level criterion at the closest noise-sensitive area (NSA), Port Arthur Pipeline

shall file with the Secretary, for review and written approval by the Director of OEP, 

an HDD noise mitigation plan to reduce the projected noise level attributable to the 

proposed drilling operations at nearby NSAs. During drilling operations, Port 

Arthur Pipeline shall implement the approved plan, monitor noise levels, and make 

all reasonable efforts to restrict the noise attributable to the drilling operations to no 

more than a day-night sound level (Ldn) of 55 decibels on the A-weighted scale 

(dBA) at the NSAs or 10 dBA above background where nighttime ambient noise is 

above 55 dBA Ldn. (section 4.11.2.3)

27. Port Arthur LNG shall file a full power load noise survey with the Secretary no 

later than 60 days after placing each Liquefaction Project train in service. If the 

noise attributable to the operation of the equipment at the liquefaction facilities 

exceeds 55 dBA Ldn at the nearest NSA, within 60 days Port Arthur LNG shall 

modify operation of the liquefaction facilities or install additional noise controls 

until a noise level below 55 dBA Ldn at the NSA is achieved. Port Arthur LNG shall 

confirm compliance with the above requirement by filing a second noise survey with 

the Secretary no later than 60 days after it installs the additional noise controls. 

(section 4.11.2.4)

28. Port Arthur LNG and Port Arthur Pipeline shall file noise surveys with the Secretary 

no later than 60 days after placing the entire Liquefaction Project facility, 

including the South Compressor Station associated with the Texas Connector 

Project, into service. If a full load condition noise survey is not possible, Port Arthur 

LNG and Port Arthur Pipeline shall provide an interim survey at the maximum 

possible horsepower load within 60 days of placing the Liquefaction Project facility 

and South Compressor Station into service and provide the full load survey within 

6 months. If the noise attributable to operation of the equipment at the Liquefaction 

Project facility and South Compressor Station exceeds 55 dBA Ldn at the nearest 

NSA under interim or full horsepower load conditions, Port Arthur LNG and Port 

Arthur Pipeline shall file a report on what changes are needed and shall install the 
Docket No. CP17-20-000, et al. - 67 -

additional noise controls to meet the level within 1 year of the in-service date. Port 

Arthur LNG and Port Arthur Pipeline shall confirm compliance with the above 

requirement by filing an additional noise survey with the Secretary no later than 

60 days after it installs the additional noise controls. (section 4.11.2.4)

29. Port Arthur Pipeline shall file a noise survey with the Secretary no later than 60 

days after placing the Texas Connector Project North Compressor Station and 

Louisiana Connector Project’s compressor station in service. If a full load condition 

noise survey is not possible, Port Arthur Pipeline shall instead file an interim survey 

at the maximum possible horsepower load and file the full load survey within 6 

months. If the noise attributable to the operation of all of the equipment at any 

station under interim or full horsepower load exceeds 55 dBA Ldn at any nearby 

NSA, Port Arthur Pipeline shall file a report on what changes are needed and shall 

install the additional noise controls to meet the level within 1 year of the in-service 

date. Port Arthur Pipeline shall confirm compliance with the 55 dBA Ldn

requirement by filing a second noise survey with the Secretary no later than 60 

days after it installs the additional noise controls. (section 4.11.2.4)

30. Prior to construction of final design, Port Arthur LNG shall file with the Secretary 

the following information, stamped and sealed by the professional engineer-ofrecord, registered in Texas:

a. site preparation drawings and specifications;

b. LNG terminal structures and foundation design drawings and calculations 

(including prefabricated and field constructed structures);

c. seismic specifications for procured equipment; and

d. quality control procedures to be used for civil/structural design and 

construction.

In addition, Port Arthur LNG shall file, in its Implementation Plan, the schedule 

for producing this information. (section 4.12.6)

31. Prior to commencement of service, Port Arthur LNG shall file with the Secretary 

a monitoring and maintenance plan, stamped and sealed by the professional 

engineer-of-record registered in Texas, for the perimeter levee which ensures the 

crest elevation relative to mean sea level will be maintained for the life of the facility 

considering berm settlement, subsidence, and sea level rise. (section 4.12.6)

Conditions 32 through 126 shall apply to the Port Arthur Liquefaction Project.

Information pertaining to these specific conditions below shall be filed with the Secretary 

for review and written approval by the Director of OEP, or the Director’s designee, 

within the timeframe indicated by each condition. Specific engineering, vulnerability, or 
Docket No. CP17-20-000, et al. - 68 -

detailed design information meeting the criteria specified in Order No. 833 (Docket No. 

RM16-15-000), including security information, shall be submitted as critical energy 

infrastructure information pursuant to 18 C.F.R. 388.113. See Critical Electric 

Infrastructure Security and Amending Critical Energy Infrastructure Information, Order 

No. 833, 81 Fed. Reg. 93,732 (December 21, 2016), FERC Stats. & Regs. 31,389 (2016). 

Information pertaining to items such as offsite emergency response, procedures for public 

notification and evacuation, and construction and operating reporting requirements will 

be subject to public disclosure. All information shall be filed a minimum of 30 days

before approval to proceed is requested.

32. Prior to initial site preparation, Port Arthur LNG shall file an overall project 

schedule, which includes the proposed stages of the commissioning plan. (section 

4.12.6)

33. Prior to initial site preparation, Port Arthur LNG shall file quality assurance and 

quality control procedures for construction activities. (section 4.12.6)

34. Prior to initial site preparation, Port Arthur LNG shall file procedures for 

controlling access during construction. (section 4.12.6)

35. Prior to initial site preparation, Port Arthur LNG shall develop an emergency 

response plan (ERP) (including evacuation) and coordinate procedures with the U.S. 

Coast Guard; state, county, and local emergency planning groups; fire departments; 

state and local law enforcement; and appropriate federal agencies. This plan shall

include at a minimum: 

a. designated contacts with state and local emergency response agencies;

b. scalable procedures for the prompt notification of appropriate local officials 

and emergency response agencies based on the level and severity of potential 

incidents;

c. procedures for notifying residents and recreational users within areas of 

potential hazard;

d. evacuation routes/methods for residents and public use areas that are within 

any transient hazard areas along the route of the LNG marine transit;

e. locations of permanent sirens and other warning devices; and

f. an “emergency coordinator” on each LNG carrier to activate sirens and other 

warning devices.
Docket No. CP17-20-000, et al. - 69 -

Port Arthur LNG shall notify the FERC staff of all planning meetings in advance 

and shall report progress on the development of its ERP at 3-month intervals. 

(section 4.12.6)

36. Prior to initial site preparation, Port Arthur LNG shall file a Cost-Sharing Plan 

identifying the mechanisms for funding all Project-specific security/emergency 

management costs that will be imposed on state and local agencies. This 

comprehensive plan shall include funding mechanisms for the capital costs 

associated with any necessary security/emergency management equipment and 

personnel base. Port Arthur LNG shall notify FERC staff of all planning meetings 

in advance and shall report progress on the development of its Cost Sharing Plan at

3-month intervals. (section 4.12.6)

37. Prior to construction of final design, Port Arthur LNG shall file change logs that 

list and explain any changes made from the front-end-engineering-design (FEED)

provided in Port Arthur LNG’s application and filings. A list of all changes with an 

explanation for the design alteration shall be filed and all changes shall be clearly 

indicated on all diagrams and drawings. (section 4.12.6)

38. Prior to construction of final design, Port Arthur LNG shall file 

information/revisions pertaining to Port Arthur LNG’ response numbers 9, 11, 18, 

19, 24, 28, 29, 30-33, 34, 36-41, 43-46, 54-55 of its January 29, 2018 filing and 52 

and 57 of its February 7, 2018 filing, which indicated features to be included or 

considered in the final design. (section 4.12.6)

39. Prior to construction of final design, Port Arthur LNG shall file a plot plan of the 

final design showing all major equipment, structures, buildings, and impoundment 

systems. (section 4.12.6)

40. Prior to construction of final design, Port Arthur LNG shall file three-dimensional 

plant drawings to confirm plant layout for maintenance, access, egress, and 

congestion. (section 4.12.6)

41. Prior to construction of final design, Port Arthur LNG shall file drawings of the 

storage tank piping support structure and support of horizontal piping at grade 

including pump columns, relief valves, pipe penetrations, instrumentation, and 

appurtenances. (section 4.12.6)

42. Prior to construction of final design, Port Arthur LNG shall file a complete 

specification and drawings of the proposed LNG tank design and installation. 

(section 4.12.6)
Docket No. CP17-20-000, et al. - 70 -

43. Prior to construction of final design, Port Arthur LNG shall file an up-to-date 

equipment list, process and mechanical data sheets, and specifications. The 

specifications shall include:

a. building specifications (control buildings, electrical buildings, compressor 

buildings, storage buildings, pressurized buildings, ventilated buildings, 

blast resistant buildings);

b. mechanical specifications (piping, valve, insulation, rotating equipment, heat 

exchanger, storage tank and vessel, other specialized equipment);

c. electrical and instrumentation specifications (power system specifications, 

control system specifications, Safety Instrumented Systems (SIS) 

specifications, cable specifications, other electrical and instrumentation 

specifications); and

d. security and fire safety specifications (security, passive protection, hazard 

detection, hazard control, firewater). (section 4.12.6)

44. Prior to construction of final design, Port Arthur LNG shall file a list of all codes 

and standards and the final specification document number where they are 

referenced. (section 4.12.6)

45. Prior to construction of final design, Port Arthur LNG shall file up-to-date process 

flow diagrams (PFDs) and piping and instrument diagrams (P&IDs), including 

vendor P&IDs. The PFDs shall include heat and material balances. The P&IDs 

shall include the following information:

a. equipment tag number, name, size, duty, capacity, and design conditions;

b. equipment insulation type and thickness;

c. storage tank pipe penetration size and nozzle schedule;

d. valve high pressure side and internal and external vent locations;

e. piping with line number, piping class specification, size, and insulation type 

and thickness;

f. piping specification breaks and insulation limits;

g. all control and manual valves numbered;

h. relief valves with size and set points; and

i. drawing revision number and date. (section 4.12.6)
Docket No. CP17-20-000, et al. - 71 -

46. Prior to construction of final design, Port Arthur LNG shall file P&IDs, 

specifications, and procedures that clearly show and specify the tie-in details 

required to safely connect subsequently constructed facilities with the operational 

facilities. (section 4.12.6)

47. Prior to construction of final design, Port Arthur LNG shall file a car seal 

philosophy and a list of all car-sealed and locked valves consistent with the P&IDs. 

(section 4.12.6)

48. Prior to construction of final design, the engineering, procurement, and 

construction contractor shall verify that the recommendations from the FEED

Hazard Identification are complete and consistent with the requirements of the final 

design as determined by the engineering, procurement, and construction contractor. 

(section 4.12.6)

49. Prior to construction of final design, Port Arthur LNG shall file a hazard and 

operability review review prior to issuing the P&IDs for construction. A copy of 

the review, a list of the recommendations, and actions taken on the 

recommendations shall be filed. (section 4.12.6)

50. Prior to construction of final design, Port Arthur LNG shall file the safe operating 

limits (upper and lower), alarm and shutdown set points for all instrumentation (i.e., 

temperature, pressures, flows, and compositions). (section 4.12.6)

51. Prior to construction of final design, Port Arthur LNG shall file cause-and-effect 

matrices for the process instrumentation, fire and gas detection system, and 

emergency shutdown (ESD) system for review and approval. The cause-and-effect 

matrices shall include alarms and shutdown functions, details of the voting and 

shutdown logic, and set points. (section 4.12.6)

52. Prior to construction of final design, Port Arthur LNG shall file an evaluation of 

ESD valve closure times. The evaluation shall account for the time to detect an 

upset or hazardous condition, notify plant personnel, and close the ESD valve. 

(section 4.12.6)

53. Prior to construction of final design, Port Arthur LNG shall file an evaluation of 

dynamic pressure surge effects from valve opening and closure times and pump 

operations. (section 4.12.6)

54. Prior to construction of final design, Port Arthur LNG shall demonstrate that 

hazardous fluid piping and piping nipples 2 inches or less in diameter are designed 

to withstand external loads, including vibrational loads in the vicinity of rotating 

equipment and operator live loads in areas accessible by operators. (section 4.12.6)
Docket No. CP17-20-000, et al. - 72 -

55. Prior to construction of final design, Port Arthur LNG shall specify that all drains 

from high pressure hazardous fluid systems are equipped with double isolation and 

bleed valves. (section 4.12.6)

56. Prior to construction of final design, Port Arthur LNG shall file electrical area 

classification drawings. (section 4.12.6)

57. Prior to construction of final design, Port Arthur LNG shall file drawings and 

details of how process seals or isolations installed at the interface between a 

flammable fluid system and an electrical conduit or wiring system meet the 

requirements of National Fire Protection Association (NFPA) 59A (2001). (section 

4.12.6)

58. Prior to construction of final design, Port Arthur LNG shall file details of an air 

gap or vent installed downstream of process seals or isolations installed at the 

interface between a flammable fluid system and an electrical conduit or wiring 

system. Each air gap shall vent to a safe location and be equipped with a leak 

detection device that shall continuously monitor for the presence of a flammable 

fluid, alarm the hazardous condition, and shut down the appropriate systems. 

(section 4.12.6)

59. Prior to construction of final design, Port Arthur LNG shall include layout and 

design specifications of the pig trap, inlet separation and liquid disposal, inlet/sendout meter station, and pressure control. (section 4.12.6)

60. Prior to construction of final design, Port Arthur LNG shall specify that piping 

and equipment that may be cooled with liquid nitrogen will be designed for liquid 

nitrogen temperatures, with regard to allowable movement and stresses. (section 

4.12.6)

61. Prior to construction of final design, Port Arthur LNG shall include LNG tank fill 

flow measurement with high flow alarm. (section 4.12.6)

62. Prior to construction of final design, Port Arthur LNG shall include boil-off gas

flow, tank density profile, and temperature profile measurement for each tank. 

(section 4.12.6)

63. Prior to construction of final design, Port Arthur LNG shall file the structural 

analysis of the LNG storage tank and outer concrete impoundment wall to

demonstrate they are designed to withstand all loads and combinations. (section 

4.12.6)

64. Prior to construction of final design, Port Arthur LNG shall file an analysis of the 

structural integrity of the outer containment of the full containment storage tanks 

when exposed to a roof tank top fire or adjacent tank top fire. (section 4.12.6)
Docket No. CP17-20-000, et al. - 73 -

65. Prior to construction of final design, Port Arthur LNG shall file the sizing basis 

and capacity for the final design of the flares and/or vent stacks as well as the 

pressure and vacuum relief valves for major process equipment, vessels, and storage 

tanks. (section 4.12.6)

66. Prior to construction of final design, Port Arthur LNG shall file detailed cooldown 

plans showing the piping flow, valve alignment, and instruments used to monitor 

the initial cooldown and filling of the LNG storage tanks. (section 4.12.6)

67. Prior to construction of final design, Port Arthur LNG shall file detailed 

procedures for import of LNG during the initial cooldown of the LNG storage tanks 

including detailed P&IDs with flow paths and valve alignment showing the position 

of valves and lockout/tagout devices. (section 4.12.6)

68. Prior to construction of final design, Port Arthur LNG shall file an evaluation on 

the need to install fixed toxic gas detection to detect hydrogen sulfide (H2S) releases 

from loss of containment from the acid gas piping system and potential release 

points (i.e., vents, relief valves, vent stacks, and thermal oxidizer stack). (section 

4.12.6)

69. Prior to construction of final design, Port Arthur LNG shall file process 

simulation results for the deethanizer, depropanizer depressurized conditions to 

ensure the associated deethanizer, depropanizer, reboiler, piping, and other 

associated equipment are adequately designed for settle out and upset conditions to 

prevent brittle facture of piping and associated equipment. (section 4.12.6)

70. Prior to construction of final design, Port Arthur LNG shall file an evaluation 

assessing the minimum design metal temperature and material of construction 

needed for the deethanizer, depropanizer, reboiler and piping during upset/settleout 

conditions. (section 4.12.6)

71. Prior to construction of final design, Port Arthur LNG shall include provisions to 

maintain stability and pressure of the regenerator in the event that the H2S scavenger 

or thermal oxidizer are unavailable (e.g., change out, maintenance, startup, etc.). 

(section 4.12.6)

72. Prior to construction of final design, Port Arthur LNG shall include a thermal 

relief valve between the propane shutoff valves (XV-30687 and XV0-30686) to 

protect piping. (section 4.12.6)

73. Prior to construction of final design, Port Arthur LNG shall include a thermal 

relief valve between the ethane shutoff valves (XV0-30729 and XV0-30731) to 

protect piping. (section 4.12.6)
Docket No. CP17-20-000, et al. - 74 -

74. Prior to construction of final design, Port Arthur LNG shall include provisions to 

prevent cryogenic fluids accumulated in the dry flare knockout drum from reaching 

the wet flare knockout drum, which are connected by the dry flare knockout drum 

drain line to the blow case purge to the wet flare knockout drum. (section 4.12.6)

75. Prior to construction of final design, Port Arthur LNG shall include details of the 

flare knockout drum heater and detailed procedures for draining flare knockout 

drums to a safe location. (section 4.12.6)

76. Prior to construction of final design, Port Arthur LNG shall file detailed 

calculations for the flow rate of the jockey pumps accounting for flow rate losses 

due to leaks or when drain valves are opened to ensure that system losses do not 

exceed the specified design flow rate of the jockey firewater pumps. (section 4.12.6)

77. Prior to construction of final design, Port Arthur LNG shall file an evaluation of 

the need to install pressure relieving protection for flammable liquid piping 

segments (i.e., refrigerants, liquid hydrocarbons, condensate products) that can be 

isolated by valves. (section 4.12.6)

78. Prior to construction of final design, Port Arthur LNG shall specify that all ESD 

valves will be equipped with open and closed position switches connected to the 

Distributed Control System (DCS)/SIS. (section 4.12.6)

79. Prior to construction of final design, Port Arthur LNG shall file a drawing 

showing the location of the ESD buttons. Emergency shutdown buttons shall be 

easily accessible, conspicuously labeled, and located in an area which will be 

accessible during an emergency. (section 4.12.6)

80. Prior to construction of final design, Port Arthur LNG shall file drawings and 

specifications for vehicle barriers at each facility entrance for access control. 

(section 4.12.6)

81. Prior to construction of final design, Port Arthur LNG shall file an evaluation of

the need to install turning lanes to minimize the risk of hazardous material truck and 

other vehicle incidents entering and exiting the facility from State Highway 87. 

(section 4.12.6)

82. Prior to construction of final design, Port Arthur LNG shall file an evaluation of

the need for installing internal road vehicle protections (e.g., guard rails, barriers, 

and bollards) to protect transfer piping, pumps, and compressors, etc. and to ensure 

that they are located away from roadway or protected from inadvertent damage from 

vehicles. (section 4.12.6)

83. Prior to construction of final design, Port Arthur LNG shall file a projectile 

analysis for review and approval to demonstrate that the outer concrete 
Docket No. CP17-20-000, et al. - 75 -

impoundment wall of a full-containment LNG tank could withstand windborne 

projectiles. The analysis shall detail the projectile speeds and characteristics and 

method used to determine penetration or perforation depths. (section 4.12.6)

84. Prior to construction of final design, Port Arthur LNG shall file security camera, 

intrusion detection, and lighting drawings. The security camera drawings 

shall show the location, areas covered, and features of the camera (fixed, 

tilt/pan/zoom, motion detection alerts, low light, mounting height, etc.) to verify 

camera coverage of the entire perimeter with redundancies for cameras interior to 

the facility to enable rapid monitoring of the LNG plant. The intrusion detection 

drawings shall show or note the location of the intrusion detection to verify it covers 

the entire perimeter of the LNG plant. The lighting drawings shall show the 

location, elevation, type of light fixture, and lux levels of the lighting system. 

(section 4.12.6)

85. Prior to construction of final design, Port Arthur LNG shall file the details of the 

ESD system, including whether a plant-wide ESD button with proper sequencing 

and reliability will be installed or whether another system will be installed that is

demonstrated through a human reliability analysis to provide a means to quickly and 

reliably shutdown the entire plant. (section 4.12.6)

86. Prior to construction of final design, Port Arthur LNG shall file an updated fire 

protection evaluation of the proposed facilities. A copy of the evaluation, a list of 

recommendations and supporting justifications, and actions taken on the 

recommendations shall be filed. (section 4.12.6)

87. Prior to construction of final design, Port Arthur LNG shall file spill containment 

system drawings with dimensions and slopes of curbing, trenches, impoundments, 

and capacity calculations considering any foundations and equipment within 

impoundments, as well as the sizing and design of the down-comer that will transfer 

spills from the tank top to the ground-level impoundment system. The spill 

containment drawings shall show containment for all hazardous fluids from the 

largest flow from a single line for 10 minutes or from the largest vessel or otherwise 

demonstrate spill containment will not significantly reduce the flammable vapor 

dispersion or radiant heat consequences of a spill. (section 4.12.6)

88. Prior to construction of final design, Port Arthur LNG shall specify the material 

of construction for the curbed areas, trenches, and impoundments as insulated 

concrete or otherwise demonstrate insulated concrete will not significantly reduce 

the flammable vapor dispersion or radiant heat consequences of a spill. (section 

4.12.6)

89. Prior to construction of final design, Port Arthur LNG shall file an analysis of the 

localized hazards to operators from a potential liquid nitrogen release and shall also 
Docket No. CP17-20-000, et al. - 76 -

provide spill containment and low oxygen detectors to mitigate liquid nitrogen 

releases. (section 4.12.6)

90. Prior to construction of final design, Port Arthur LNG shall file complete 

drawings and a list of the hazard detection equipment. The drawings shall clearly 

show the location and elevation of all detection equipment and demonstrate 

potential releases resulting in an offsite impact could be detected by at least two 

detectors to allow for shutdown in less than 10 minutes. The list shall include the 

instrument tag number, type and location, alarm indication locations, and shutdown 

functions of the hazard detection equipment. (section 4.12.6)

91. Prior to construction of final design, Port Arthur LNG shall file a list of alarm and 

shutdown set points for all hazard detectors that account for the calibration gas of 

the hazard detectors when determining the lower flammable limit set points for 

methane, propane, butane, ethane, and condensate. (section 4.12.6)

92. Prior to construction of final design, Port Arthur LNG shall file a list of alarm and 

shutdown set points for all hazard detectors that account for the calibration gas of 

hazard detectors when determining the set points for toxic components such as 

aqueous ammonia, natural gas liquids and H2S. (section 4.12.6)

93. Prior to construction of final design, Port Arthur LNG shall file a technical review 

of facility design that:

a. identifies all combustion/ventilation air intake equipment and the distances 

to any possible flammable gas or toxic release; and

b. demonstrates that these areas are adequately covered by hazard detection 

devices and indicates how these devices will isolate or shutdown any 

combustion or heating ventilation and air conditioning equipment whose 

continued operation could add to or sustain an emergency. (section 4.12.6)

94. Prior to construction of the final design, Port Arthur LNG shall file a building 

siting assessment to ensure plant buildings that are occupied or critical to the safety 

of the LNG plant are adequately protected from potential hazards involving fires 

and vapor cloud explosions. (section 4.12.6)

95. Prior to construction of final design, Port Arthur LNG shall file a drawing that 

includes smoke detection in occupied buildings. (section 4.12.6)

96. Prior to construction of final design, Port Arthur LNG shall file a drawing that 

includes hazard detection suitable to detect high temperatures and smoldering 

combustion products in electrical buildings and control room buildings. (section 

4.12.6)
Docket No. CP17-20-000, et al. - 77 -

97. Prior to construction of final design, Port Arthur LNG shall file a drawing that 

includes clean agent systems in the electrical switchgear and instrumentation 

buildings. (section 4.12.6)

98. Prior to construction of final design, Port Arthur LNG shall file facility plan 

drawings and a list of the fixed and wheeled dry-chemical, hand-held fire 

extinguishers, and other hazard control equipment. Plan drawings shall clearly 

show the location by tag number and elevation of all fixed, wheeled, and hand-held 

extinguishers and demonstrate travel distances are along normal paths of access and 

egress and in compliance with NFPA 10, 15, and 17. The list shall include the 

equipment tag number, type, capacity, equipment covered, discharge rate, and 

automatic and manual remote signals initiating discharge of the units. (section 

4.12.6)

99. Prior to construction of final design, Port Arthur LNG shall file facility plan 

drawings showing the proposed location of the firewater and any foam systems. 

Plan drawings shall clearly show the location of firewater and foam piping, post 

indicator valves, and the location and area covered by, each monitor, hydrant, hose, 

water curtain, deluge system, foam system, water-mist system, and sprinkler. The 

drawings shall demonstrate that each process area, fire zone, or other sections of 

piping with several users can be isolated with post indicator valves and that firewater 

coverage is provided by at least two monitors or hydrants with sufficient firewater 

flow to cool exposed surfaces subjected to a fire. Drawings shall also include piping 

and instrumentation diagrams of the firewater and foam systems. (section 4.12.6)

100. Prior to construction of final design, Port Arthur LNG shall file detailed 

calculations to confirm that the final fire water volumes will be accounted for when 

evaluating the capacity of the impoundment system during a spill and fire scenario. 

(section 4.12.6)

101. Prior to construction of final design, Port Arthur LNG shall specify that the 

firewater flow test meter is equipped with a transmitter and that a pressure 

transmitter is installed upstream of the flow transmitter. The flow transmitter and 

pressure transmitter shall be connected to the DCS and recorded. (section 4.12.6)

102. Prior to construction of final design, Port Arthur LNG shall specify that the 

firewater pump shelter is designed with a removable roof for maintenance access to 

the firewater pumps. (section 4.12.6)

103. Prior to construction of final design, Port Arthur LNG shall file calculations for 

the firewater spray systems sized to provide cooling for mitigation of boiling-liquidexpanding-vapor explosions. (section 4.12.6)
Docket No. CP17-20-000, et al. - 78 -

104. Prior to construction of final design, Port Arthur LNG shall file a design that 

accounts for the fire water required for foam generation in calculating the total fire 

water required for 2 hours of supply. (section 4.12.6)

105. Prior to construction of final design, Port Arthur LNG shall file drawings and 

specifications for the structural passive protection systems to protect equipment and 

supports from cryogenic releases. (section 4.12.6)

106. Prior to construction of final design, Port Arthur LNG shall file a detailed 

quantitative analysis to demonstrate that adequate thermal mitigation will be 

provided for each significant component within the 4,000 BTU/ft2

-hr zone from an 

impoundment, or provide an analysis that evaluates the consequences of pressure 

vessel bursts and boiling liquid expanding vapor explosions. Trucks at the truck 

transfer station shall be included in the analysis. Passive mitigation shall be 

supported by calculations for the thickness limiting temperature rise and active 

mitigation shall be justified with calculations demonstrating flow rates and 

durations of any cooling water to mitigate the heat absorbed by the vessel. (section 

4.12.6)

107. Prior to construction of final design, Port Arthur LNG shall file an evaluation of 

the voting logic and voting degradation for hazard detectors. (section 4.12.6)

108. Prior to commissioning, Port Arthur LNG shall file a detailed schedule for 

commissioning through equipment startup. The schedule shall include milestones 

for all procedures and tests to be completed: prior to introduction of hazardous 

fluids and during commissioning and startup. Port Arthur LNG shall file 

documentation certifying that each of these milestones has been completed before 

authorization to commence the next phase of commissioning and startup will be 

issued. (section 4.12.6)

109. Prior to commissioning, Port Arthur LNG shall file detailed plans and procedures 

for: testing the integrity of onsite mechanical installation; functional tests; 

introduction of hazardous fluids; operational tests; and placing the equipment into 

service. (section 4.12.6)

110. Prior to commissioning, Port Arthur LNG shall file a plan for clean-out, dry-out, 

purging, and tightness testing. This plan shall address the requirements of the 

American Gas Association’s Purging Principles and Practice, and shall provide 

justification if not using an inert or non-flammable gas for clean-out, dry-out, 

purging, and tightness testing. (section 4.12.6)

111. Prior to commissioning, Port Arthur LNG shall file the procedures for 

pressure/leak tests which address the requirements of American Society of 

Mechanical Engineers (ASME) Boiler and Pressure Vessel Code section VIII, and 
Docket No. CP17-20-000, et al. - 79 -

ASME B31.3. The procedures shall include a line list of pneumatic and hydrostatic 

test pressures. (section 4.12.6)

112. Prior to commissioning, Port Arthur LNG shall file the operation and maintenance 

procedures and manuals, as well as safety procedures, hot work procedures and 

permits, abnormal operating conditions reporting procedures, simultaneous 

operations procedures, and management of change procedures and forms. (section 

4.12.6)

113. Prior to commissioning, Port Arthur LNG shall tag all equipment, instrumentation, 

and valves in the field, including drain valves, vent valves, main valves, and carsealed or locked valves. (section 4.12.6) 

114. Prior to commissioning, Port Arthur LNG shall file a plan to maintain a detailed 

training log to demonstrate that operating staff has completed the required training. 

(section 4.12.6)

115. Prior to commissioning, Port Arthur LNG shall equip the LNG storage tank and 

adjacent piping and supports with permanent settlement monitors to allow personnel 

to observe and record the relative settlement between the LNG storage tank and 

adjacent piping. The settlement record shall be reported in the semi-annual

operational reports. (section 4.12.6)

116. Prior to introduction of hazardous fluids, Port Arthur LNG shall develop and 

implement an alarm management program to reduce alarm complacency and 

maximize the effectiveness of operator response to alarms. (section 4.12.6)

117. Prior to introduction of hazardous fluids, Port Arthur LNG shall file results of 

the LNG storage tank hydrostatic test and foundation settlement results. At a 

minimum, foundation settlement results shall be provided thereafter annually. 

(section 4.12.6)

118. Prior to introduction of hazardous fluids, Port Arthur LNG shall complete and 

document all pertinent tests (Factory Acceptance Tests, Site Acceptance Tests, Site 

Integration Tests) associated with the DCS and SIS that demonstrates full 

functionality and operability of the system. (section 4.12.6)

119. Prior to introduction of hazardous fluids, Port Arthur LNG shall complete and 

document a firewater pump acceptance test and firewater monitor and hydrant 

coverage test. The actual coverage area from each monitor and hydrant shall be 

shown on facility plot plan(s). (section 4.12.6)

120. Prior to introduction of hazardous fluids, Port Arthur LNG shall complete and 

document a pre-startup safety review to ensure that installed equipment meets the 

design and operating intent of the facility. The pre-startup safety review shall
Docket No. CP17-20-000, et al. - 80 -

include any changes since the last hazard review, operating procedures, and operator 

training. A copy of the review with a list of recommendations, and actions taken on 

each recommendation, shall be filed. (section 4.12.6)

121. Port Arthur LNG shall file a request for written authorization from the 

Director of OEP prior to unloading or loading the first LNG commissioning 

cargo. After production of first LNG, Port Arthur LNG shall file weekly reports 

on the commissioning of the proposed systems that detail the progress toward 

demonstrating the facilities can safely and reliably operate at or near the design 

production rate. The reports shall include a summary of activities, problems 

encountered, and remedial actions taken. The weekly reports shall also include the 

latest commissioning schedule, including projected and actual LNG production by 

each liquefaction train, LNG storage inventories in each storage tank, and the 

number of anticipated and actual LNG commissioning cargoes, along with the 

associated volumes loaded or unloaded. Further, the weekly reports shall include a 

status and list of all planned and completed safety and reliability tests, work 

authorizations, and punch list items. Problems of significant magnitude shall be 

reported to the FERC within 24 hours. (section 4.12.6)

122. Prior to commencement of service, Port Arthur LNG shall label piping with fluid 

service and direction of flow in the field, in addition to the pipe labeling 

requirements of NFPA 59A (2001). (section 4.12.6)

123. Prior to commencement of service, Port Arthur LNG shall provide plans for any 

preventative and predictive maintenance program that performs periodic or 

continuous equipment condition monitoring. (section 4.12.6)

124. Prior to commencement of service, Port Arthur LNG shall develop procedures for 

offsite contractors’ responsibilities, restrictions, and limitations and for supervision 

of these contractors by Port Arthur LNG staff. (section 4.12.6)

125. Prior to commencement of service, Port Arthur LNG shall notify the FERC staff 

of any proposed revisions to the security plan and physical security of the plant. 

(section 4.12.6)

126. Prior to commencement of service, Port Arthur LNG shall file a request for written 

authorization from the Director of OEP. Such authorization will only be granted 

following a determination by the U.S. Coast Guard, under its authorities under the 

Ports and Waterways Safety Act, the Magnuson Act, the Maritime Transportation 

Security Act of 2002, and the Security and Accountability For Every Port Act, that 

appropriate measures to ensure the safety and security of the facility and the 

waterway have been put into place by Port Arthur LNG or other appropriate parties. 

(section 4.12.6)
Docket No. CP17-20-000, et al. - 81 -

In addition, recommendations 127 through 130 shall apply throughout the life of the 

Port Arthur Liquefaction facility.

127. The facility shall be subject to regular FERC staff technical reviews and site 

inspections on at least an annual basis or more frequently as circumstances indicate. 

Prior to each FERC staff technical review and site inspection, Port Arthur LNG shall 

respond to a specific data request including information relating to possible design 

and operating conditions that may have been imposed by other agencies or 

organizations. Up-to-date detailed P&IDs reflecting facility modifications and 

provision of other pertinent information not included in the semi-annual reports 

described below, including facility events that have taken place since the previously 

submitted semi-annual report, shall be submitted. (section 4.12.6)

128. Semi-annual operational reports shall be filed with the Secretary to identify 

changes in facility design and operating conditions; abnormal operating 

experiences; activities (e.g., ship arrivals, quantity and composition of imported and 

exported LNG, liquefied and vaporized quantities, boil off/flash gas); and plant 

modifications, including future plans and progress thereof. Abnormalities shall 

include, but not be limited to, unloading/loading/shipping problems, potential 

hazardous conditions from offsite vessels, storage tank stratification or rollover, 

geysering, storage tank pressure excursions, cold spots on the storage tanks, storage 

tank vibrations and/or vibrations in associated cryogenic piping, storage tank 

settlement, significant equipment or instrumentation malfunctions or failures, nonscheduled maintenance or repair (and reasons therefore), relative movement of 

storage tank inner vessels, hazardous fluids releases, fires involving hazardous 

fluids and/or from other sources, negative pressure (vacuum) within a storage tank, 

and higher than predicted boil off rates. Adverse weather conditions and the effect 

on the facility also shall be reported. Reports shall be submitted within 45 days 

after each period ending June 30 and December 31. In addition to the above 

items, a section entitled “Significant Plant Modifications Proposed for the Next 12 

Months (dates)” shall be included in the semi-annual operational reports. Such 

information will provide the FERC staff with early notice of anticipated future 

construction/maintenance at the LNG facilities. (section 4.12.6)

129. In the event the temperature of any region of any secondary containment, including 

imbedded pipe supports, becomes less than the minimum specified operating 

temperature for the material, the Commission shall be notified within 24 hours and

procedures for corrective action shall be specified. (section 4.12.6)

130. Significant non-scheduled events, including safety-related incidents (e.g., LNG, 

condensate, refrigerant, or natural gas releases; fires; explosions; mechanical 

failures; unusual over pressurization; and major injuries) and security-related 

incidents (e.g., attempts to enter site, suspicious activities) shall be reported to the 
Docket No. CP17-20-000, et al. - 82 -

FERC staff. In the event that an abnormality is of significant magnitude to threaten 

public or employee safety, cause significant property damage, or interrupt service, 

notification shall be made immediately, without unduly interfering with any 

necessary or appropriate emergency repair, alarm, or other emergency procedure. 

In all instances, notification shall be made to the FERC staff within 24 hours. This 

notification practice shall be incorporated into the liquefaction facility’s emergency 

plan. Examples of reportable hazardous fluids-related incidents include:

a. fire; 

b. explosion;

c. estimated property damage of $50,000 or more;

d. death or personal injury necessitating in-patient hospitalization;

e. release of hazardous fluids for 5 minutes or more;

f. unintended movement or abnormal loading by environmental causes, such as 

an earthquake, landslide, or flood, that impairs the serviceability, structural 

integrity, or reliability of an LNG facility that contains, controls, or processes 

hazardous fluids;

g. any crack or other material defect that impairs the structural integrity or 

reliability of an LNG facility that contains, controls, or processes hazardous 

fluids; 

h. any malfunction or operating error that causes the pressure of a pipeline or 

LNG facility that contains or processes hazardous fluids to rise above its 

maximum allowable operating pressure (or working pressure for LNG 

facilities) plus the build-up allowed for operation of pressure-limiting or 

control devices; 

i. a leak in an LNG facility that contains or processes hazardous fluids that 

constitutes an emergency; 

j. inner tank leakage, ineffective insulation, or frost heave that impairs the 

structural integrity of an LNG storage tank;

k. any safety-related condition that could lead to an imminent hazard and cause 

(either directly or indirectly by remedial action of the operator), for purposes 

other than abandonment, a 20 percent reduction in operating pressure or 

shutdown of operation of a pipeline or an LNG facility that contains or 

processes hazardous fluids; 
Docket No. CP17-20-000, et al. - 83 -

l. safety-related incidents from hazardous fluids transportation occurring at or 

en route to and from the LNG facility; or

m. an event that is significant in the judgment of the operator and/or 

management even though it did not meet the above criteria or the guidelines 

set forth in an LNG facility’s incident management plan. 

In the event of an incident, the Director of OEP has delegated authority to take 

whatever steps are necessary to ensure operational reliability and to protect human 

life, health, property, or the environment, including authority to direct the 

liquefaction facility to cease operations. Following the initial company 

notification, the FERC staff would determine the need for a separate follow-up 

report or follow up in the upcoming semi-annual operational report. All company 

follow-up reports shall include investigation results and recommendations to 

minimize a reoccurrence of the incident. (section 4.12.6)
UNITED STATES OF AMERICA

FEDERAL ENERGY REGULATORY COMMISSION

Port Arthur LNG, LLC

PALNG Common Facilities Company, LLC

Port Arthur Pipeline, LLC

Docket No.

Docket Nos.

CP17-20-000

CP17-21-000

CP17-21-001

CP18-7-000

(Issued April 18, 2019)

GLICK, Commissioner, dissenting: 

I dissent from today’s order because it violates both the Natural Gas Act1 (NGA) 

and the National Environmental Policy Act2 (NEPA). In particular, the Commission is 

again refusing to consider the consequences its actions have for climate change. Neither 

the NGA nor NEPA permit the Commission to assume away the climate change 

implications of constructing and operating this liquefied natural gas (LNG) facility. Yet 

that is precisely what the Commission is doing today.

In the order authorizing Port Arthur LNG, LLC’s LNG export terminal (LNG 

Terminal) pursuant to section 3 of the NGA and the associated natural gas pipelines

(Pipeline Projects) pursuant to section 7 of the NGA (collectively, Project), the 

Commission treats GHG emissions differently than all other environmental impacts. By 

refusing to assess the significance of the impact of the Project’s GHG emissions, even 

after quantifying them, the Commission not only neglects its obligation to assess the 

environmental impacts, but also its concomitant duty to explore possible mitigation 

measures to reduce any significant adverse effects. This systematic failure to consider 

the Project’s impacts on climate change is what allows the Commission to misleadingly 

state that “[a]ll [environmental] impacts . . . will be reduced to less-than-significant

 1 15 U.S.C. §§ 717b, 717f (2012).

2 National Environmental Policy Act of 1969, 42 U.S.C. §§ 4321 et seq.

(continued ...)
Docket No. CP17-20-000, et al. - 2 -

levels”3 and, as a result, conclude that the Project satisfies the NGA’s public interest 

standards.

4

I. The Commission’s Public Interest Determinations Are Not the Product of 

Reasoned Decisionmaking

The NGA’s regulation of LNG import and export facilities “implicate[s] a tangled 

web of regulatory processes” split between the U.S. Department of Energy (DOE) and 

the Commission.5 The NGA establishes a general presumption favoring the import and 

export of LNG unless there is an affirmative finding that the import or export “will not be 

consistent with the public interest.”6 Section 3 of the NGA, which governs LNG imports

and exports, provides for two independent public interest determinations: one regarding 

the import or export of LNG itself and one regarding the facilities used for that import or 

export. DOE determines whether the import or export of LNG is consistent with the 

public interest, with transactions among free trade countries legislatively deemed to be 

“consistent with the public interest.”7 The Commission evaluates whether “an 

application for the siting, construction, expansion, or operation of an LNG terminal” is 

 3 Port Arthur LNG, LLC, 167 FERC ¶ 61,052, at P 101 (2019) (Certificate Order);

see also Final Environmental Impact Statement at ES-10 (Final EIS).

4 Certificate Order, 167 FERC ¶ 61,052 at PP 29, 36.

5 Sierra Club v. FERC, 827 F.3d 36, 40 (D.C. Cir. 2016) (Freeport). 

6 15 U.S.C. §717b(a); see EarthReports, Inc. v. FERC, 828 F.3d 949, 953 (D.C. 

Cir. 2016) (citing W. Va. Pub. Servs. Comm’n v. Dep’t of Energy, 681 F.2d 847, 856 

(D.C. Cir. 1982) (“NGA [section] 3, unlike [section] 7, ‘sets out a general presumption 

favoring such authorization.’”)). Under section 7 of the NGA, the Commission approves 

a proposed pipeline if it is shown to be consistent with the public interest, while under 

section 3, the Commission approves a proposed LNG import or export facility unless it is 

shown to be inconsistent with the public interest. Compare 15 U.S.C. § 717b(a) with 15 

U.S.C. §717f(a), (e).

7 15 U.S.C. § 717b(c). The courts have explained that, because the authority to 

authorize LNG exports rests with DOE, NEPA does not require the Commission to 

consider the upstream or downstream GHG emissions that may be indirect effects of the 

export itself when determining whether the related LNG export facility satisfies section 3 

of the NGA. See Freeport, 827 F.3d at 46-47; see also Sierra Club v. FERC, 867 F.3d 

1357, 1373 (D.C. Cir. 2017) (Sabal Trail) (discussing Freeport). NEPA still requires, 

however, that the Commission consider the direct GHG emissions associated with a 

proposed LNG export facility. See Freeport, 827 F.3d at 41, 46.

(continued ...)
Docket No. CP17-20-000, et al. - 3 -

consistent with the public interest.8 Pursuant to that authority, the Commission must 

approve a proposed LNG facility unless the record shows that the facility would be 

inconsistent with the public interest.9 

As part of that determination, the Commission must examine a proposed LNG 

facility’s impact on the environment and public safety. A facility’s impact on climate 

change must be part of a public interest determination under the NGA.10 Nevertheless, 

the Commission maintains that it need not consider whether the Project’s contribution to 

climate change is significant because it lacks a means to do so—or at least so it claims.11 

However, the shocking part of the Commission’s rationale is what comes next. Based on 

this alleged inability to assess significance, the Commission concludes that the Project 

will have no significant environmental impact.12 That is the equivalent of saying that an 

action that is known to be dangerous is actually safe because we do not know exactly 

how dangerous it is. That is ludicrous and it certainly does not give climate change the 

serious consideration it deserves and that the law demands. 

The Commission’s failure to consider the impact of the Project’s GHG emissions

is all-the-more glaring given the volume of emissions at issue in this proceeding. The 

Commission points out that the operation of the Project will directly emit 4.77 million 

 8 15 U.S.C. § 717b(e). In 1977, Congress transferred the regulatory functions of 

NGA section 3 to DOE. DOE, however, subsequently delegated to the Commission 

authority to approve or deny an application for the siting, construction, expansion, or 

operation of an LNG terminal, while retaining the authority to determine whether the 

import or export of LNG to non-free trade countries is in the public interest. See 

EarthReports, Inc., 828 F.3d at 952-53.

9 See Freeport, 827 F.3d at 40-41.

10 See Sabal Trail, 867 F.3d at 1373 (explaining that the Commission may “deny a 

pipeline certificate on the ground that the pipeline would be too harmful to the 

environment”); see also Atl. Ref. Co. v. Pub. Serv. Comm’n of N.Y., 360 U.S. 378, 391 

(1959) (holding that the NGA requires the Commission to consider “all factors bearing 

on the public interest”).

11 Certificate Order, 167 FERC ¶ 61,052 at P 138; see also Final EIS at 4-361‒4-

362 (explaining that “[t]here is no generally accepted methodology to estimate what 

extent a project’s incremental contribution to [GHG] emissions would result in physical 

effects on the environment”).

12 Certificate Order, 167 FERC ¶ 61,052 at P 101; Final EIS at ES-10.

(continued ...)
Docket No. CP17-20-000, et al. - 4 -

metric tons of GHGs annually.13 Given the Commission’s acknowledgment of that GHG 

emissions contribute to climate change,14 the decision to exclude GHG emissions from 

playing any role in the Commission’s public interest analysis is indefensible. 

The implications of the Commission’s approach to evaluating the impacts of GHG 

emissions extend beyond any single proceeding under NGA section 3 or section 7. 

Taking the Commission’s approach to its logical conclusion, the Commission would 

approve any project regardless of the amount of GHGs emitted without ever determining 

the significance of their environmental impact. If the Commission’s assessment of that

impact will not change no matter the volume of GHG emissions at issue, those emissions 

and their consequences cannot meaningfully factor into the public interest determination. 

Approving a project that may significantly contribute to the harms caused by climate 

change without meaningfully evaluating the significance of that impact or considering it 

as part of the public interest determination is contrary to law, arbitrary and capricious, 

and not the product of reasoned decisionmaking.15

II. The Commission Fails to Satisfy Its Obligations under NEPA

In order to evaluate the environmental consequences of the Project under NEPA, 

the Commission must consider the harm caused by the Project’s GHG emissions and 

“evaluate the ‘incremental impact’ that these emissions will have on climate change or 

the environment more generally.”16 As noted, the Final EIS states that the Project will 

directly emit 4.77 million metric tons of GHGs annually.17 Although that quantification 

 13 Certificate Order, 167 FERC ¶ 61,052 at P 137; Final EIS at Table 4.11.1-7

(Carbon dioxide emissions in the Final EIS are expressed in short tons.).

14 Final EIS at 4-360.

15 As noted, the NGA “requires the Commission to evaluate all factors bearing on 

the public interest,” Atl. Ref. Co., 360 U.S. at 391, which Sabal Trail held includes a 

facility’s contribution to the harms caused by climate change, 867 F.3d at 1373.

16 Ctr. for Biological Diversity v. Nat’l Highway Traffic Safety Admin., 538 F.3d 

1172, 1216 (9th Cir. 2008); WildEarth Guardians v. Zinke, No. CV 16-1724 (RC), 2019 

WL 1273181, at *1 (D.D.C. Mar. 19, 2019) (explaining that the agency was required to 

“provide the information necessary for the public and agency decisionmakers to 

understand the degree to which [its] decisions at issue would contribute” to the “impacts 

of climate change in the state, the region, and across the country”).

17 Supra note 13.

(continued ...)
Docket No. CP17-20-000, et al. - 5 -

of the Project’s GHG emissions is a necessary step toward meeting the Commission’s 

NEPA obligations, listing the volume of emissions alone is insufficient.18

As an initial matter, identifying the consequences that those emissions will have 

for climate change is essential if NEPA is to play the disclosure and good government 

roles for which it was designed. The Supreme Court has explained that NEPA’s purpose 

is to “ensure[] that the agency, in reaching its decision, will have available, and will 

carefully consider, detailed information concerning significant environmental impacts” 

and to “guarantee[] that the relevant information will be made available to the larger 

audience that may also play a role in both the decisionmaking process and the 

implementation of that decision.”19 It is hard to see how hiding the ball on a project’s 

climate impacts is consistent with either of those purposes. 

In addition, under NEPA, a finding of significance informs the Commission’s

inquiry into potential ways of mitigating environmental impacts.20 The Supreme Court 

has held that an EIS must “contain a detailed discussion of possible mitigation measures” 

to address adverse environmental impacts.21 The Court explained that, “[w]ithout such a 

discussion, neither the agency nor other interested groups and individuals can properly 

evaluate the severity of the adverse effects” of a project, making an examination of 

possible mitigation measures necessary to ensure that the agency has taken a “hard look” 

at the environmental consequences of the action at issue.22 Consistent with this 

 18 See Ctr. for Biological Diversity, 538 F.3d at 1216 (“While the [environmental 

document] quantifies the expected amount of CO2 emitted . . . , it does not evaluate the 

‘incremental impact’ that these emissions will have on climate change or on the 

environment more generally . . . .”); Klamath-Siskiyou Wildlands Ctr. v. Bureau of Land 

Mgmt., 387 F.3d 989, 995 (9th Cir. 2004) (“A calculation of the total number of acres to 

be harvested in the watershed is a necessary component . . . , but it is not a sufficient 

description of the actual environmental effects that can be expected from logging those 

acres.”).

19 Dep’t of Transp. v. Pub. Citizen, 541 U.S. 752, 768 (2004) (citing Robertson v. 

Methow Valley Citizens Coun., 490 U.S. 332, 349 (1989)).

20 40 C.F.R. § 1502.16 (2018) (NEPA requires an implementing agency to form a 

“scientific and analytic basis for the comparisons” of the environmental consequences of 

its action in its environmental review, which “shall include discussions of . . . [d]irect 

effects and their significance.”).

21 Robertson, 490 U.S. at 351.

22 Id. at 352; see also 40 C.F.R. §§ 1508.20 (defining mitigation), 1508.25 

(continued ...)
Docket No. CP17-20-000, et al. - 6 -

obligation, the Final EIS discusses mitigation measures to ensure that the Project’s 

adverse environmental impacts, excluding GHG emissions, are reduced to less than 

significant levels.23 For example, in order to find that the Project’s impacts on wetlands 

are not anticipated to be significant,

24 the Commission relies on compensatory mitigation 

including the purchase of mitigation credits.25 The Commission not only has the 

obligation to discuss mitigation of adverse environmental impacts under NEPA, but also 

the authority to condition certificates under section 3 and 7 of the NGA.26 Once again, 

however, the Project’s climate change impacts are treated differently. By refusing to 

assess significance, the Commission escapes its obligation to consider mitigation 

measures for the Project’s GHG emissions. 

In refusing to even assess the significance of the Project’s GHG emissions during 

the environmental review process, the Commission relegates climate change to a 

negligible role, at best, in its NEPA analysis. Nothing in today’s order justifies this 

result. The Commission argues that it cannot determine whether the Project’s 

contribution to climate change is significant, relying on the premise that there is no 

“generally accepted methodology” to estimate a project’s impact on climate change, 

either locally or nationally.27 As a logical matter, the argument that there is no single 

standard methodology for evaluating the significance of GHG emissions does not excuse 

the Commission from assessing the Project’s environmental impacts under NEPA. The 

 

(including in the scope of an environmental impact statement mitigation measures).

23 Certificate Order, 167 FERC ¶ 61,052 at PP 102, 106, 109, 112, 114, 128 (The 

Commission states that adverse environmental impacts to geology, water, wetlands, 

vegetation, wildlife, and air quality will not be significant if the Applicant implements 

proposed mitigation measures.).

24 Final EIS at ES-6.

25 Id.; see also Final EIS at 4-58–4-59 (The U.S. Army Corp of Engineers has a 

goal of “no net loss” for wetlands and requires compensatory mitigation for all permanent 

wetland loss. The Final EIS relies on multiple mitigation measures including contributed 

dredging materials for emergent wetlands and wetland mitigation credit purchases.).

26 15 U.S.C. § 717b(e)(3)(A); 15 U.S.C. § 717f(e); Certificate Order, 167 FERC 

¶ 61,052 at P 141 (“[T]he Commission has the authority to take whatever steps are 

necessary to ensure the protection of environmental resources . . . , including authority to 

impose any additional measures deemed necessary . . . .”). 

27 Final EIS at 4-361–4-362; see also Certificate Order, 167 FERC ¶ 61,052 at P 

138. 

(continued ...)
Docket No. CP17-20-000, et al. - 7 -

claimed absence of a standard methodology is no justification for effectively ignoring 

those emissions.28 

Moreover, the argument that there is no single standard methodology for 

evaluating the significance of GHG emissions is a red herring. The lack of any single 

methodology does not prevent the Commission from adopting a methodology, even if 

others are available. The Commission has several tools to assess the harm from the 

Project’s contribution to climate change. By measuring the long-term damage done by a 

ton of carbon dioxide, the Social Cost of Carbon links GHG emissions to actual

environmental effects from climate change, thereby facilitating the necessary “hard look” 

at the Project’s environmental impacts that NEPA requires. Especially when it comes to 

a global problem like climate change, a measure for translating a single project’s climate 

change impacts into concrete and comprehensible terms plays a useful role in the NEPA 

process by putting the harm in terms that are readily accessible for both agency 

decisionmakers and the public at large. Yet, the Commission continues to ignore the 

Social Cost of Carbon, relying instead on deeply flawed reasoning that I have previously 

critiqued at length.29 

Regardless of tools or methodologies available, the Commission can use its 

judgement and discretion to consider all factors and determine, quantitatively or 

qualitatively, whether the Project’s GHG emissions have a significant impact on climate 

change. After all, that is precisely what the Commission does in other aspects of its 

environmental review. For example, consider the Commission’s evaluation of the 

Project’s impact on the surrounding land. The Final EIS determines that a total of 992 

 28 My colleague, Commissioner LaFleur, wrestled with these questions and 

reached a judgment on both the significance of the impact of the GHG emissions and the 

merits of the Project notwithstanding the lack of analysis in the Commission’s order. 

Certificate Order, 167 FERC ¶ 61,052 (LaFleur, Comm’r, concurring at P 8). Providing 

additional context regarding the Project’s GHG emissions and their cumulative impact is 

a useful first step that promotes public disclosure and informed decisionmaking. But 

neither that context nor a concurrence assessing the significance of the impact of the 

Project’s GHG emissions can remedy the order’s erroneous conclusion that the 

Commission cannot evaluate the significance of the Project’s contribution to climate 

change or its assumption that such a contribution is insignificant. Nor can a concurrence 

remedy the absence of any discussion in the record of the significance of the Project’s 

contribution to climate change.

29 See, e.g., Fla. Se. Connection, LLC, 164 FERC ¶ 61,099 (2018) (Glick, 

Comm’r, dissenting).

(continued ...)
Docket No. CP17-20-000, et al. - 8 -

acres of vegetation and upland forest will be permanently affected by the Project,30 but 

then concludes that the Project “will not have a significant impact on vegetation.”31 The 

Final EIS provides no “standard methodology” available to the Commission to evaluate 

this impact.32 Instead, the Commission uses its judgment to conduct a qualitative review 

to assess the Project’s impact on vegetation and conclude that the impact would not be 

significant based on the “minor nature of the impacts.”33 The Commission’s refusal to 

exercise similar qualitative discretion and judgment when it comes to evaluating the 

impacts of GHG emissions is arbitrary and capricious and willfully ignorant.

The Commission’s refusal to seriously consider the significance of the impact of 

the Project’s GHG emissions is even more mystifying because NEPA “does not dictate 

particular decisional outcomes.”34 NEPA “‘merely prohibits uninformed—rather than 

unwise—agency action.’”35 Taking the matter seriously—and rigorously examining a 

project’s impacts on climate change—does not necessarily prevent any of my colleagues 

from ultimately concluding that a project meets the public interest standard. Indeed, a 

thorough investigation of a project’s contribution to climate change would also help 

infrastructure developers by reducing their legal risk in the appeals that will inevitably 

follow. At the end of the day, no one benefits from the Commission’s refusal to consider 

a project’s impact on climate change.

For these reasons, I respectfully dissent.

______________________________

Richard Glick

Commissioner

 30 Certificate Order, 167 FERC ¶ 61,052 at PP 110-111.

31 Id. P 112.

32 As compared to the Commission’s requirement for a “standard methodology” to 

determine the significance of the Project’s GHG emissions, as discussed in Certificate 

Order, 167 FERC ¶ 61,052 at P 138 (citing to Dominion Transmission, Inc., 163 FERC ¶ 

61,128, at PP 67-70 (2018) (LaFleur, Comm’r, dissenting in part; Glick, Comm’r, 

dissenting in part)).

33 Id. P 112.

34 Sierra Club v. U.S. Army Corps of Engineers, 803 F.3d 31, 37 (D.C. Cir. 2015).

35 Id. (quoting Robertson, 490 U.S. at 351).
UNITED STATES OF AMERICA

FEDERAL ENERGY REGULATORY COMMISSION

Port Arthur LNG, LLC

PALNG Common Facilities Company, LLC

Port Arthur Pipeline, LLC

Docket Nos. CP17-20-000

CP17-21-000

CP17-21-001

CP18-7-000

(Issued April 18, 2019)

LaFLEUR, Commissioner, concurring: 

Today’s order grants authorization to Port Arthur LNG, LLC and PALNG 

Common Facilities Company, LLC (collectively Port Arthur LNG) pursuant to section 3 

of the Natural Gas Act (NGA),

1 to site, construct and operate a new liquefied natural gas 

(LNG) export terminal (Port Arthur LNG Project) in Port Arthur, Texas.

2

 The 

Commission also authorizes Port Arthur Pipeline, LLC (Port Arthur Pipeline), pursuant 

to section 7 of the NGA,3 to construct and operate both, the Texas Connector Project to 

provide up to 2,000,000 dekatherms per day (Dth/day) of natural gas transportation 

service to the proposed export terminal and the Louisiana Connector Project to provide 

2,000,000 Dth/day to the proposed export terminal. For the reasons discussed below, I 

concur.

Under section 3 of the NGA, oversight for LNG export is divided between the 

Commission and the U.S. Department of Energy (DOE). Specifically, it is the DOE, not 

the Commission, which retains the exclusive authority over the export of the natural gas 

as a commodity, including the responsibility to consider whether the exportation of that

 1

 15 U.S.C. § 717b (2012).

2 Port Arthur LNG, LLC, 167 FERC ¶ 61,052 (2019) (Certificate Order).

3 15 U.S.C. § 717f(c) (2012).

(continued ...)
Docket No. CP17-20-000, et al. - 2 -

gas is in the public interest.4

 If the export will be sent to a free trade country, the NGA 

automatically “deems” the export “to be consistent with the public interest.”5

 

This framework leaves the Commission with the limited authority to approve or 

deny an application for the siting, construction, expansion, or operation of the LNG 

terminal facilities. In exercising its section 3 authority, the Commission’s responsibility 

includes conducting a public interest analysis to consider the technical and environmental 

aspects of the LNG facilities themselves. Our environmental review is governed by the 

National Environmental Policy Act6 (NEPA) which, as relevant here, requires the 

Commission to take a “hard look” at the potential environmental impacts that could result 

from the Port Arthur LNG Project, including the climate change impacts of the proposed 

project. 

The U.S. Court of Appeals for the D.C. Circuit (D.C. Circuit) has made clear that 

the DOE, rather than the Commission, has the responsibility to assess upstream and 

downstream indirect GHG emission impacts of LNG exports as part of the DOE’s 

determination of the public interest in exporting the natural gas.7

 However, the 

Commission still has the clear responsibility to disclose and consider the direct and 

cumulative GHG impacts of the proposed LNG export facility, and make significance 

determinations regarding such impacts, in order to satisfy our obligations under NEPA 

and section 3 of the NGA. 

I appreciate that the Commission has disclosed in the Certificate Order the direct 

GHG emissions of the Port Arthur LNG Project and the Texas and Louisiana Connector 

pipeline projects, and has provided important context by comparing them to the national 

GHG emissions inventory.8

 We have included this comparison in the past to provide 

 4 15 U.S.C. § 717b(a)-(c) (2012).

5 15 U.S.C. § 717b(c) (2012).

6 National Environmental Policy Act of 1969, 42 U.S.C. §§ 4321 et seq.

7 Sierra Club v. FERC, 827 F.3d 36, 47 (D.C. Cir. 2016) (Freeport) (“[T]he 

Commission’s NEPA analysis did not have to address the indirect effects of the 

anticipated export of natural gas. That is because the Department of Energy, not the 

Commission, has the sole authority to license the export of any natural gas going through 

the Freeport facilities.”). See also Sierra Club v. FERC, 827 F.3d 59 (D.C. Cir. 2016) 

(Sabine Pass); EarthReports, Inc. v. FERC, 823 F.3d 949 (D.C. Cir. 2016). 

8 Certificate Order, 167 FERC ¶ 61,052 at P 137. Final Environmental Impact 

Statement (EIS) at Table 4.11.1-7. The Final EIS also discloses the direct GHG 

emissions from the construction of the LNG terminal and the pipelines: 197,714 metric 

(continued ...)
Docket No. CP17-20-000, et al. - 3 -

context to the indirect emissions of pipeline projects, and the D.C. Circuit has taken note 

of the Commission’s efforts to use available national, regional, and state emissions 

inventories as part of our climate change analysis.9

 

I recognize that the disclosure of the data, and the context provided, is only the 

first step to assist the Commission in determining the significance of a given rate or 

volume of GHG emissions as part of our climate change analysis. As a second step, 

NEPA requires that we analyze that information to determine whether a specific impact 

is, in fact, significant. 10 Unfortunately, to date, the Commission has not established a 

framework for making a significance determination. However, the magnitude of the 

direct GHG emission from the Port Arthur LNG Project are substantial and certainly 

appear to be significant as contemplated by NEPA. 

 

tons during the multiple years of construction. Table 4.11.1-4, 4.11.1-5 and 4.11.1-

6. See Sierra Club v. FERC, 867 F.3d 1357 at 1374 (D.C. Cir. 2017) (Sabal Trail) 

(“Quantification would permit the agency to compare the emissions from this project to 

emissions from other projects, to total emissions from the state or the region, or to 

regional or national emissions-control goals.”)

9 E.g., Town of Weymouth, Mass. v. FERC, No. 17-1135, 2018 WL 6921213 (D.C. 

Cir. Dec. 27, 2018)(per curiam) (speaking approvingly of the Commission’s 

quantification of the project’s expected GHG emissions, which included a comparison of 

the Atlantic Bridge Project against state and regional climate change goals.); Appalachian 

Voices v. FERC, No. 17-1721 (D.C. Cir. Feb. 19, 2019) (per curiam) (dismissing claims 

that FERC failed to adequately consider downstream climate impacts of the Mountain 

Valley Pipeline project by noting, among other things, that “FERC provided an estimate 

of the upper bound of emissions resulting from end-use combustion...”). By comparison, 

in Sabal Trail, the D.C. Circuit vacated and remanded the Commission’s authorization of 

the Southeast Market Pipeline Project and directed the Commission to both quantify and 

consider the project’s downstream GHG emissions or explain in more detail why it 

cannot do so. In response to the Court order, the Commission quantified the net, gross, 

and full-burn of downstream GHG emissions and compared them to the state and national 

GHG emissions inventories. 

10 Under NEPA, when evaluating the significance of a particular impact, the 

Commission must consider both context and intensity. 40 C.F.R. § 1508.27(a) (2017) 

(Context means “that the significance of an action must be analyzed in several contexts 

such as society as a whole (human, national), the affected region, the affected interests 

and the locality.”). 40 C.F.R. § 1508.27(b) (2017) (Intensity refers to “the severity of the 

impact”).

(continued ...)
Docket No. CP17-20-000, et al. - 4 -

I remain frustrated by the Commission’s continued refusal to even consider how 

we might develop a framework for assessing the potential significance of GHG 

emissions.

11 While it might be easier to assess significance if we had national emissions 

reduction targets, like EPA’s Clean Power Plan or the Paris Climate Accord,12 to use as 

part of our framework, the lack of such targets does not prevent the Commission from 

making a significance determination in this or in any other case. In fact, the Commission 

makes challenging determinations on quantitative and qualitative issues in many other 

areas of our work.13

 11 In my concurrence on the Driftwood LNG Project, I explain that finding the 

GHG emissions to be significant does not mean the Commission cannot approve a 

proposed project. NEPA requires the Commission to disclose and consider all

environmental impacts of a proposed action, but NEPA does not mandate particular 

results, it simply prescribes the necessary process for considering each impact. Once a 

significant impact has been identified then the next logical step is to think about ways to 

mitigate that impact. Driftwood LNG LLC, 167 FERC ¶ 61,054 (2019) (LaFleur, 

Comm’r, concurring at PP 9-10) (citing KN Wattenberg Transmission LLC, 90 FERC ¶ 

61,322, at 62,083 (2000) (citing and quoting Robertson v. Methow Valley Citizens 

Council, 490 U.S. 332, 350 (1989)). 

12 As noted in the Certificate Order, the EPA’s Clean Power Plan and the Paris 

climate account are pending repeal and withdrawal, respectively. Certificate Order, 167 

FERC ¶ 61,052 at P 137, nt. 194. 

13 Many of the core areas of the Commission’s work have required the 

development of analytical frameworks, often a combination of quantitative measurements 

and qualitative assessments, to fulfill the Commission’s responsibilities under its broad 

authorizing statutes. This work regularly requires that the Commission exercise 

judgment, based on its expertise, precedent, and the record before it. For example, to 

help determine just and reasonable returns on equity (ROEs) under the Federal Power 

Act, Natural Gas Act, and Interstate Commerce Act, the Commission identifies a proxy 

group of comparably risky companies, applies a method or methods to determine a range 

of potentially reasonable ROEs (i.e., the zone of reasonableness), and then considers 

various factors to determine the just and reasonable ROE within that range. See also, 

e.g., Promoting Transmission Investment through Pricing Reform, Order No. 679, FERC 

Stats. & Regs. ¶ 31,222, order on reh’g, Order No. 679-A, FERC Stats. & Regs. ¶ 31,236 

(2006), order on reh’g, 119 FERC ¶ 61,062 (2007) (establishing Commission regulations 

and policy for reviewing requests for transmission incentives); Transmission Planning 

and Cost Allocation by Transmission Owning and Operating Public Utilities, Order No. 

1000, FERC Stats. & Regs. ¶ 31,323 (2011), order on reh’g, Order No. 1000-A, 139 

FERC ¶ 61,132, order on reh’g and clarification, Order No. 1000-B, 141 FERC ¶ 61,044 

(continued ...)
Docket No. CP17-20-000, et al. - 5 -

I do not believe it is beyond the capability of this Commission to determine 

whether a given rate or volume of GHG emissions should be considered significant. The 

Commission has grappled with every other identifiable and measurable environmental 

impact; for example, we quantify, consider, and mitigate impacts to land, water, and 

species, and we make determinations on whether the impacts to wetlands or mussels are 

significant.14 For reasons that I do not find persuasive, the Commission treats climate 

impacts differently than all other environmental impacts in our environmental review, 

and refuses to make such determinations regarding climate change impacts. Instead, the 

Commission summarily finds that because it cannot decide how to conduct a meaningful 

analysis of climate change impacts, it is not required to conduct any analysis of 

significance. I disagree. 

With regards to cumulative impacts analysis, I appreciate that the analysis in the 

final EIS addresses a range of resources impacted within the identified geographic scope 

of the Port Arthur LNG Project. However, as I highlighted in my concurrence in 

 

(2012), aff’d sub nom. S.C. Pub. Serv. Auth. v. FERC, 762 F.3d 41 (D.C. Cir. 2014) 

(requiring, among other things, the development of regional cost allocation methods 

subject to certain general cost allocation principles); BP Pipelines (Alaska) Inc., Opinion 

No. 544, 153 FERC ¶ 61,233 (2015) (conducting a prudence review of a significant 

expansion of the Trans Alaska Pipeline System). I also note that the Commission is 

currently actively considering a broad topic – resilience – whose scope and complexity 

might similarly require the development of new analytical frameworks for conducting the 

Commission’s work.

14 In the Final EIS, the Commission made a significance determination on: 

geology, soils, water resources, wildlife, aquatic resources, wetlands, vegetation, wildlife 

resources, land use, recreation, and visual impacts, socioeconomics, air quality, noise,

and reliability and safety. The Commission also determined that adverse environmental 

impacts to geology, water, wetlands, vegetation, wildlife, and air quality would not be 

significant with the proposed mitigation measures. Moreover, in making such 

determinations, the Commission has frequently relied solely on a qualitative assessment 

and Commission staff discretion, rather than quantitative analysis, as it did with the 

vegetation impacts in this case. Certificate Order, 167 FERC ¶ 61,052 at PP 110-112. I 

reject the view that the difficulty of quantifying GHG emissions impacts is an excuse for 

failing to evaluate the significance of those impacts.

(continued ...)
Docket No. CP17-20-000, et al. - 6 -

Calcasieu Pass LNG,15 I disagree with the decision to exclude GHG emissions from the 

cumulative impacts analysis.

16

As I have stated before, it takes minimal effort to disclose the GHG emissions for 

the other FERC projects identified in the final EIS’s cumulative impacts air region, and 

include an estimate of the total annual potential GHG emissions associated with a 

proposed project and other nearby projects as part of our environmental review. I am 

disappointed that the final EIS does not do so. I recognize that using the 50 km air region 

is a rudimentary proxy for assessing the cumulative impacts of GHG emissions because 

those emissions are not typically measured on a local or regional basis.17 But disclosing 

that minimal information would at least be a start, and I believe that failure to do so 

creates added legal risk.18 

Since the Commission fails to disclose the cumulative GHG emissions numbers, I 

have included an estimate of them in Table 1 attached to my concurrence. I believe that, 

 15 Venture Global Calcasieu Pass, LLC, 166 FERC ¶ 61,144 (2019) (LaFleur, 

Comm’r, concurring).

16 Final EIS at 4-330-4-337, Table 4.13.1-1.

17 50 kilometers is the distance used in the final EIS and by the EPA for 

cumulative modeling of large sources of air pollutants (nitrogen oxides [NOx], sulfur 

oxides [SOx], particulate matter [PM], etc.), volatile organic compounds, and hazardous 

air pollutants. GHGs are not included. Final EIS at 4-324- 4-325, Table 4.13-1.

18 Recently, the U.S. District Court for D.C. criticized the Bureau of Land 

Management (BLM) for failing to disclose the cumulative impacts of GHG emissions in 

sufficient detail. The court found that NEPA requires “BLM quantify the emissions from 

each leasing decision—past, present or reasonably foreseeable—and compare those 

emissions to regional and national emissions, setting forth with reasonable specificity the 

cumulative effect of the leasing decision at issue.” WildEarth Guardians v. Zinke, No. 

CV 16-1724 (RC), 2019 WL 1273181, at *46 (D.D.C. Mar. 19, 2019). By comparison, 

the U.S. District Court for Colorado, upheld BLM, finding they took an appropriately 

hard look at cumulative climate change impacts where, the agency: (1) looked at 

statewide emissions levels from emitting coal-fired power plants in Colorado and 

provided a comparative assessment; (2) provided a qualitative analysis of climate change 

and the role played by GHG emissions; (3) performed a regional cumulative impacts 

analysis for the future mineral development in the region for ten years; and (4) quantified 

the GHG emissions from both projects. Citizens for a Healthy Cmty. v. Bureau of Land 

Mgmt., No. 1:17-CV-02519-LTB-GPG, 2019 WL 1382785, at *20-21 (D. Colo. Mar. 27, 

2019).

(continued ...)
Docket No. CP17-20-000, et al. - 7 -

consistent with our NEPA obligations, at a minimum, the GHG emissions must be 

disclosed and considered, both cumulatively and with respect to individual facilities. 

I will continue to consider and evaluate these issues as they arise in individual 

proceedings, however, I believe the Commission should proactively address these issues.

If we do not, further guidance from the courts on our NEPA responsibility to consider 

climate change will likely require us to do so. Such guidance could create additional 

legal risk and add additional complexities to our reviews under both Section 3 and 

Section 7 of the NGA. Thus, I believe that proactive solutions to this challenging problem 

must be explored. 

Given my review of the record including climate impacts, I find the Port Arthur 

LNG Project is not inconsistent with the public interest.19 As for Port Arthur Pipeline’s 

Texas Connector and Louisiana Connector Projects, which is solely serving the Port 

Arthur LNG Project, I find the pipeline is in the public convenience and necessity. The 

D.C. Circuit has recognized that, as with the appended LNG export facility, the 

downstream indirect GHG emissions for the pipeline are not part of the Commission’s 

environmental review and consideration.20 Therefore, my public interest determination is 

based on a review of the rest of the environmental review of the pipeline project. After 

carefully balancing the need for the project and its environmental impacts, I find the 

project is in the public interest. 

For these reasons, I respectfully concur.

______________________________

Cheryl A. LaFleur

Commissioner

 19 I recognize that it is difficult to balance the GHG impacts with the potential 

public benefits of export, since the latter are part of DOE’s responsibility, and the 

Commission is working under a presumption of public interest. I have considered the 

information provided by the 2014 National Energy Technology Lab (NETL), Life Cycle 

Greenhouse Gas Perspective on Exporting Liquefied Natural Gas from the United States, 

to provide some context to benefits. This analysis calculates the life cycle GHG 

emissions for regional coal and imported natural gas power in Europe and Asia. The 

approach includes GHG impacts of liquefaction and finds, on balance that export of US 

LNG has less climate impacts than some alternatives. As I have stated before, that 

analysis should be updated based on more recent information and proposed projects.

20 See Sabine Pass, 827 F.3d at 68. 
Table 1: Annual Direct CO2e Emissions from FERC Projects within about 50km Port Arthur LNG

Port Arthur 

Liquefaction

Sabine Pass LNG Golden Pass LNG

Liquefaction

South Texas Expansion 

Project

Total National Inventory for 

2016

GHG in CO2e 

(tpy)

5,190,000 10,220,000 5,330,000 5.2 20,740,005 6,395,700,000

Percent of

National 

Inventory

0.08% 0.16% 0.08% 0.00% 0.32% --

Notes: Includes LNG 

terminal; 

North, South, 

and Louisiana 

Connector 

Compressor 

Stations

Includes trains 1-6 Includes terminal 

expansion, MP 1 

Compressor Station, 

and MP 66 

Compressor Station; 

does not include 

LNG import terminal

Piping modifications to 

the existing 

launcher/receiver at MP 

412.73 on Line 16 within 

Texas Eastern’s Vidor 

Compressor Station.

This only shows the 

increase in emissions 

based on the 

modifications.

N/A Table ES-2: Net GHG 

Emissions, inclusive of

sources and sinks 

converted to english 

tons. 

https://www.epa.gov/si

tes/pr

oduction/files/2018-

01/documents/2018_co

mplet e_report.pdf