Petition for Writ of Certiorari — North Carolina Utilities Commission, Petitioner v. Federal Energy Regulatory Commission

Supreme Court briefJul 2, 2019

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No. ___

IN THE

Supreme Court of the United States

————

NORTH CAROLINA UTILITIES COMMISSION,

Petitioner,

FEDERAL ENERGY REGULATORY COMMISSION,

Respondent.

————

On Petition for a Writ of Certiorari to the

United States Court of Appeals for the

District of Columbia Circuit

————

PETITION FOR A WRIT OF CERTIORARI

————

KATHLEEN L. MAZURE

Counsel of Record

JASON T. GRAY

DUNCAN & ALLEN

1730 Rhode Island Avenue, NW

Suite 700

Washington, DC 20036

(202) 289-8400

klm@duncanallen.com

jtg@duncanallen.com

Counsel for Petitioner

July 2, 2019

WILSON-EPES PRINTING CO., INC. – (202) 789-0096 – WASHINGTON, D. C. 20002

QUESTION PRESENTED

The Natural Gas Act provides States and State

regulatory commissions procedural rights to challenge

Federal Energy Regulatory Commission orders in

order to protect States’ interests. 15 U.S.C. § 717r(a),

(b). This Court’s opinion in Massachusetts v. Environmental Protection Association, 549 U.S. 497, 518-520

(2007) held that States are entitled to special solicitude in courts’ standing analyses because they are not

normal litigants for purposes of invoking federal

jurisdiction. While courts of appeals have offered

varying views of Massachusetts’ scope, in this case,

the District of Columbia Circuit did not address

Massachusetts. Instead, it held a State litigant had

not demonstrated injury-in-fact and, therefore, lacked

standing to challenge Federal Energy Regulatory

Commission orders that authorized construction of

interstate pipeline facilities that will be located within

the State’s borders and that were marketed to serve

the State’s ratepayers.

The questions presented are:

1. If a court of appeals finds a State litigant failed

to demonstrate injury-in-fact that is traceable to the

challenged action and redressable by the court, must

it separately consider whether the State litigant has

standing under Massachusetts to challenge orders by

a federal agency that implicate the State’s quasisovereign and parens patriae interests?

2. If a federal statute affords a State litigant procedural rights to challenge agency actions that affect

the State’s quasi-sovereign and parens patriae interests, do Massachusetts and Lujan v. Defenders of

Wildlife, 504 U.S. 555, 572 n.7 (1992) require the State

to demonstrate injury-in-fact that is traceable to the

(i)

challenged action and redressable by the court in order

to establish Article III standing?

iii

PARTIES TO THE PROCEEDING

Petitioner appearing in this Court is the North

Carolina Utilities Commission. Petitioner was the

appellant in the court of appeals. Petitioner is a

governmental entity that is not required to file a Rule

29.6 statement.

Respondent is the Federal Energy Regulatory

Commission. Respondent was the appellee in the

court of appeals.

The following entities were intervenors in the court

of appeals: (1) Transcontinental Gas Pipe Line

Company, LLC; (2) The New York State Public Service

Commission; and (3) Oglethorpe Power Corporation.

TABLE OF CONTENTS

Page

QUESTION PRESENTED ..................................

PARTIES TO THE PROCEEDING ....................

iii

TABLE OF AUTHORITIES ................................

vii

OPINIONS BELOW ............................................

STATEMENT OF JURISDICTION ....................

STATUTORY AND REGULATORY

PROVISIONS INVOLVED ..............................

STATEMENT OF THE CASE ............................

Legal Framework ......................................

Procedural Background ............................

REASONS FOR GRANTING THE PETITION..

The United States Court of Appeals for

the District of Columbia Circuit Decision

Conflicts with the Supreme Court’s Decisions in Massachusetts and Lujan ...........

In Reversing the District of Columbia

Circuit’s Dismissal of the North Carolina

Commission’s Appeal, the Court Should

Address the Split Among the Circuits

and Affirm the Scope and Durability of

Massachusetts’ Special Solicitude Doctrine for State Litigants ............................

CONCLUSION ....................................................

APPENDIX

APPENDIX A: JUDGMENT, U.S. Court of

Appeals for the District of Columbia Circuit

(April 3, 2019) ..................................................

(v)

TABLE OF CONTENTS—Continued

Page

APPENDIX B: ORDER ISSUING CERTIFICATE, U.S. Federal Energy Regulatory

Commission (August 3, 2016) ..........................

APPENDIX C: ORDER DENYING REHEARING, U.S. Federal Energy Regulatory

Commission (November 21, 2017) ...................

81a

APPENDIX D: ORDER ISSUING CERTIFICATE, U.S. Federal Energy Regulatory

Commission (July 7, 2016)...............................

91a

APPENDIX E: ORDER DENYING REHEARING, U.S. Federal Energy Regulatory

Commission (November 21, 2017) ................... 130a

APPENDIX F: ORDER ISSUING CERTIFICATE, U.S. Federal Energy Regulatory

Commission (February 3, 2017) ...................... 136a

APPENDIX G: ORDER ON REHEARING,

U.S. Federal Energy Regulatory Commission

(December 6, 2017) .......................................... 274a

APPENDIX H: 15 U.S.C.S. § 717a .................. 345a

APPENDIX I: 15 U.S.C.S. § 717r .................... 347a

APPENDIX J: N.C. Gen. Stat. § 62-2.............. 351a

APPENDIX K: N.C Gen. Stat. § 62-32 ............ 357a

APPENDIX L: N.C Gen. Stat. § 62-36.01 ....... 358a

APPENDIX M: N.C Gen. Stat. § 62-48 ........... 360a

APPENDIX N: N.C Gen. Stat. § 62-133.4 ....... 362a

APPENDIX O: 18 C.F.R. § 385.214 ................. 364a

vii

TABLE OF AUTHORITIES

CASES

Page(s)

Ark. Elec. Coop. Corp. v. Ark. Pub.

Serv. Comm’n,

461 U.S. 375 (1983) ................................... 3, 7, 9

Arpaio v. Obama,

797 F.3d 11 (D.C. Cir. 2015) .....................

Center for Biological Diversity v.

Department of Interior,

563 F.3d 466 (D.C. Cir. 2009) ................... 12, 13

Connecticut v. Am. Elec. Power Co.,

582 F.3d 309 (2d Cir. 2009), juris.

aff’d by an equally divided court,

131 S. Ct. 2527 (2011) ........................... 8, 13, 14

Gvt. Province of Manitoba v.

David Bernhardt,

D.C. Cir. Case No. No. 17-5242

(May 3, 2019)....................................... 7-8, 13-14

Lujan v. Defenders of Wildlife,

504 U.S. 555 (1992) ..................................passim

Md. People’s Counsel v. FERC,

760 F.2d 318 (D.C. Cir. 1985) ...................

Massachusetts v. EPA,

549 U.S. 497 (2007) ..................................passim

N. Carolina Utilities Comm’n v. F.E.R.C.,

No. 18-1018 (D.C. Cir. April 3, 2019) ......passim

Texas v. United States,

809 F.3d 134 (5th Cir. 2015), aff’d

by an equally divided Court,

136 S. Ct. 2271 (2016) ...................... 8, 12-13, 14

viii

TABLE OF AUTHORITIES—Continued

ADMINISTRATIVE CASES

Page(s)

Transcontinental Gas Pipe Line Co., LLC,

156 FERC ¶ 61,022 (2016), on reh’g,

161 FERC ¶ 61,212 (2017) ........................

Transcontinental Gas Pipe Line Co., LLC,

156 FERC ¶ 61,092 (2016), on reh’g,

161 FERC ¶ 61,211 (2017) ........................

Transcontinental Gas Pipe Line Co., LLC,

158 FERC ¶ 61,125, on reh’g,

161 FERC ¶ 61,250 (2017) ........................

CONSTITUTION

U.S. Const. art. I, § 8, cl. 3 ...........................

U.S. Const. art. III ...................................... 4, 8, 13

STATUTES

15 U.S.C. § 717(a) .........................................

15 U.S.C. § 717(b) .........................................

15 U.S.C. § 717a(6) .......................................

15 U.S.C. § 717f(c) ........................................

3, 5

15 U.S.C. § 717f(e) ........................................

15 U.S.C. § 717n(e) ....................................... 4, 5-6

15 U.S.C. § 717r(a) ......................................passim

15 U.S.C. § 717r(b) ......................................passim

28 U.S.C. § 1254(l) ........................................

N.C. Gen. Stat. § 62-48(a) .......................... 2, 5, 11

TABLE OF AUTHORITIES—Continued

REGULATIONS

Page(s)

18 C.F.R. § 385.214(a)(2) .............................. 4, 11

RULES

Fed. R. App. P. 36 .........................................

OPINIONS BELOW

Pursuant to D.C. Circuit Rule 36, the judgement

below was not published. The judgement was issued

on April 3, 2019 in North Carolina Utilities Commission v. F.E.R.C., D.C. Circuit Case No. 18-1018. Pet.

Appendix-A at 1a-4a.

The orders of the Federal Energy Regulatory

Commission that were on appeal below are reported

at: (1) 156 FERC ¶ 61,092 (2016), Pet. Appendix-B at

5a-80a; (2) 161 FERC ¶ 61,211 (2017), Pet. AppendixC at 81a-90a; (3) 156 FERC ¶ 61,022 (2016), Pet.

Appendix-D at 91a-129a; (4) 161 FERC ¶ 61,212

(2017), Pet. Appendix-E at 130a-135a; (5) 158 FERC

¶ 61,125 (2017), Pet. Appendix-F at 136a-273a; and

(6) 161 FERC ¶ 61,250 (2017), Pet. Appendix-G at

274a-344a.

STATEMENT OF JURISDICTION

The judgement of the court of appeals was entered

on April 3, 2019. The jurisdiction of this Court is

invoked under 28 U.S.C. § 1254(1).

STATUTORY AND REGULATORY

PROVISIONS INVOLVED

In pertinent part, 15 U.S.C. § 717r(a) provides that

a “State commission aggrieved by an order issued by

the [Federal Energy Regulatory] Commission in a

proceeding under this chapter to which such . . . State

commission is a party may apply for a rehearing

within thirty days after the issuance of such order.”

Pet Appendix-I at 347a.

In pertinent part, 15 U.S.C. § 717r(b) provides:

Any party to a proceeding under this chapter

aggrieved by an order issued by the [Federal

Energy Regulatory] Commission in such

proceeding may obtain a review of such order

in the court of appeals of the United States for

any circuit wherein the natural-gas company

to which the order relates is located or has its

principal place of business, or in the United

States Court of Appeals for the District of

Columbia, by filing in such court, within sixty

days after the order of the Commission upon

the application for rehearing, a written petition praying that the order of the Commission

be modified or set aside in whole or in part.

Pet. Appendix-I at 348-349a.

Other relevant statutes and regulations are contained

in the appendix.

STATEMENT OF THE CASE

This case presents a recurring question of exceptional importance that circuit courts have grappled

with—the scope and durability of this Court’s holding

in Massachusetts v. EPA, 549 U.S. 497 (2007) regarding the special solicitude afforded to State litigants

that challenge federal agency actions affecting the

State’s interests. Petitioner in the case below, the

North Carolina Utilities Commission (“North Carolina

Commission”), “is authorized and empowered to initiate and appear before federal and State courts and

agencies as in its opinion may be necessary to secure

for the users of public utility service in [North

Carolina] just and reasonable rates and service” (N.C.

Gen. Stat. § 62-48(a), Pet. Appendix-M at 360a). The

North Carolina Commission sought judicial review of

Federal Energy Regulatory Commission (“FERC”) orders

that authorized construction of interstate pipeline

facilities that were marketed to the State’s citizens

and that will be constructed and operated within the

State’s borders. The North Carolina Commission

asserted that Massachusetts entitled it to special

solicitude in the court’s standing analysis. Petitioner

Initial Brief at 32-34; Petitioner Reply Brief at 19-21.

Without addressing Massachusetts, the District of

Columbia Circuit dismissed the appeal on the grounds

that the North Carolina Commission failed to demonstrate injury-in-fact and, therefore, lacks standing.

Pet. Appendix-A at 1a-4a. This finding conflicts

directly with this Court’s holding in Massachusetts;

ignores the procedural rights the Natural Gas Act

affords State litigants to challenge FERC orders (15

U.S.C. § 717r(a), (b), Pet. Appendix-I at 347a-349a);

and deprives North Carolina of the ability to protect

its quasi-sovereign and parens patriae interests in

interstate pipeline facilities that will be constructed

and operated within North Carolina’s borders and the

rates paid by North Carolina citizens for service on

those facilities.

A. Legal Framework

1. Congress vested the authority to regulate interstate commerce solely in the federal government. US

Const. Art. I, Sec. 8, Cl. 3. The Natural Gas Act vested

the power to regulate interstate transportation of

natural gas to FERC’s predecessor, the Federal Power

Commission. 15 U.S.C. § 717(a), (b). FERC’s regulatory powers include the authority to determine

whether construction and operation of interstate

pipeline facilities is in the public interest. 15 U.S.C.

§ 717f(c), (e).

2. “[T]he regulation of utilities is one of the most

important of the functions traditionally associated

with the police power of the States.” Ark. Elec. Coop.

Corp. v. Ark. Pub. Serv. Comm’n, 461 U.S. 375, 377

(1983). If a State had not joined the Union, it would

have the sovereign right to regulate public utilities

that construct facilities located within its borders and

that serve its citizens. By joining the Union, however,

States relinquished that right to the extent those

public utilities engage in interstate commerce. States

must rely on the federal government to protect their

interests when interstate pipelines impact the State

and its citizens.

3. Though the Natural Gas Act vested FERC

with authority to regulate interstate transportation

of natural gas, it recognized States’ special status

concerning matters over which FERC has jurisdiction.

The Natural Gas Act expressly recognizes States and

State commissions as “parties” that may participate in

FERC proceedings. 15 U.S.C. § 717n(e); cf. 18 C.F.R.

§ 385.214(a)(2) (unlike other parties that must seek

leave to intervene, FERC’s regulations authorize State

commissions to intervene in proceedings as a matter

of right, without motion), Pet. Appendix-O at 364a365a. “The special solicitude for states and state

agencies is also reflected in the provision governing

those who may apply for rehearing, which is a prerequisite for judicial review.” Md. People’s Counsel v.

FERC, 760 F.2d 318, 320-21 (D.C. Cir. 1985) (discussing 15 U.S.C. § 717r(a), Pet. Appendix-I at 347a). In

addition, the Natural Gas Act provides a procedural

right to seek relief from federal courts if they are

“aggrieved” by FERC orders. 15 U.S.C. § 717r(b), Pet.

Appendix-I at 348a-349a.

4. To establish Article III standing, a litigant must

demonstrate injury-in-fact that is traceable to the

challenged action and redressable by the court. Lujan

v. Defenders of Wildlife, 504 U.S. 555, 559-61(1992).

However, a litigant “who has been accorded a procedural right to protect his concrete interests can

assert that right without meeting all the normal

standards of redressability and immediacy.” Id., at

572, n.7. This Court’s Massachusetts decision requires

courts to afford State litigants special solicitude when

analyzing standing, especially where Congress has

provided the State litigant a concomitant procedural

right to challenge actions by federal agencies that

negatively impact the State’s once-sovereign prerogatives. Massachusetts, 549 U.S. at 518-20.

B. Procedural Background

5. Transcontinental Gas Pipe Line Company, LLC

(“Transco”) is a natural gas pipeline company as

defined by Natural Gas Act section 2(6). 15 U.S.C.

§ 717a(6), Pet. Appendix-H at 345a. In March 2015,

Transco initiated the three FERC proceedings that

give rise to this Petition by seeking authorization

under 15 U.S.C. § 717f(c) to construct and operate

interstate pipeline facilities. Pet. Appendix-B at 5a8a; Pet. Appendix-D at 91a-93a; Pet. Appendix-F at

136a-140a. Those facilities were marketed to serve

North Carolina residents and, in part, be constructed

within North Carolina’s borders. Pet. Appendix-B at

5a-7a; Pet. Appendix-D at 93a, 126a; Pet. Appendix-F

at 136a-140a.

6. North Carolina law authorizes and empowers

the North Carolina Commission “to . . . appear before

federal . . . courts and agencies as in its opinion

may be necessary to secure for the users of public

utility service in [North Carolina] just and reasonable

rates and service.” N.C. Gen. Stat. § 62-48(a), Pet.

Appendix-M at 360a. Given that Transco’s proposed

facilities implicated North Carolina’s quasi-sovereign

and parens patriae interests in interstate natural gas

pipeline facilities that will be constructed and operated in North Carolina and the rates paid by North

Carolina ratepayers for service on those facilities, the

North Carolina Commission became “party” to those

FERC proceedings as the Natural Gas Act defines that

term (15 U.S.C. § 717n(e)). Pet. Appendix-B at 10a;

Pet. Appendix-D at 94a-95a; Pet. Appendix-F at 144a.

The North Carolina Commission raised substantive

concerns with Transco’s proposals, arguing that they

negatively impacted North Carolina’s interests. Pet.

Appendix-B at 10a; Pet. Appendix-D at 94a-96a; Pet.

Appendix-F at 144a-145a. Aggrieved by the manner

in which FERC’s orders impacted North Carolina’s

interests, the North Carolina Commission sought

rehearing and judicial review of FERC’s orders under

15 U.S.C. § 717r(a), (b). Pet. Appendix-C at 81a-82a;

Pet. Appendix-E at 130a-131a; Pet. Appendix-G at

275a-282a.

7. On appeal before the District of Columbia

Circuit, the North Carolina Commission asserted that

FERC’s orders resulted in an injury-in-fact to North

Carolina’s interests that was traceable to the orders

and redressable by the court. Petitioner Initial Brief

at 29-32; see also Petitioner Reply Brief at 5-19. The

North Carolina Commission also asserted that the

District of Columbia Circuit must afford the North

Carolina Commission special solicitude when analyzing standing under Massachusetts. Petitioner Initial

Brief at 32-34; see also Petitioner Reply Brief at 19-21.

8. On April 3, 2019, the District of Columbia

Circuit dismissed the appeal on the grounds that the

North Carolina Commission did not demonstrate

injury-in-fact. Pet. Appendix-A at 1a-4a. The District

of Columbia Circuit did not address Massachusetts or

acknowledge North Carolina’s special status as a

State litigant with a concomitant procedural right to

challenge FERC orders.

REASONS FOR GRANTING THE PETITION

The Court should grant this Petition because the

District of Columbia’s standing analysis is in direct

conflict with this Court’s decision in Massachusetts.

Massachusetts requires courts to afford State litigants

special solicitude when analyzing questions of standing, especially when Congress has provided the State

a concomitant procedural right to challenge federal

agency actions that negatively impact the State’s oncesovereign prerogatives and interests of its citizens.

Massachusetts, 549 U.S. 518-20. In that regard, the

District of Columbia’s standing analysis is also in

direct conflict with this Court’s holding in Lujan that

a litigant “who has been accorded a procedural right

to protect his concrete interests can assert that

right without meeting all the normal standards of

redressability and immediacy.” Lujan, 504 at 572, n.7.

“The regulation of utilities is one of the most important

of the functions traditionally associated with the police

power of the States.” Ark. Elec. Coop., 461 U.S. at 377.

Because the Natural Gas Act vests FERC with jurisdiction over interstate pipeline matters that affect

North Carolina’s quasi-sovereign and parens patriae

interests, the District of Columbia Circuit’s failure

to follow Massachusetts and Lujan deprives North

Carolina of the ability to protect those interests with

regard to interstate pipeline facilities that are constructed and operated within North Carolina’s borders

and rates paid by North Carolina citizens for service

on those facilities.

The Court should grant this Petition because it

presents an opportunity to address questions of exceptional importance—the scope and durability of Massachusetts. Circuit courts have grappled with interpreting Massachusetts’ scope and meaning. See Gvt.

Province of Manitoba v. David Bernhardt, D.C. Cir.

Case No. No. 17-5242, Slip Op. at 13 (May 3, 2019)

(“Massachusetts v. EPA is not a parens patriae case.

There is some confusion on this score most possibly

caused by the opinion’s discussion of quasi-sovereign

interests.”); see also Connecticut v. Am. Elec. Power

Co., 582 F.3d 309, 337 (2d Cir. 2009) (“the Massachusetts Court . . . arguably muddled state proprietary and

parens patriae standing”), aff’d by an equally divided

Court; see also id. at 338 (“The question is whether

Massachusetts’ discussion of state standing has an

impact on the analysis of parens patriae standing[.]

That is, what is the role of the Article III parens

patriae standing in relation to the test set out in

Lujan?”); Texas v. United States, 809 F.3d 134 (5th Cir.

2015) (affording special solicitude doctrine relying on

parens patriae standing), aff’d by an equally divided

Court, 136 S. Ct. 2271, 2272 (2016).

A. The United States Court of Appeals for the

District of Columbia Circuit Decision

Conflicts with the Supreme Court’s Decisions in Massachusetts and Lujan.

On appeal before the District of Columbia Circuit,

the North Carolina Commission submitted that it met

the traditional, three-part standing test for establishing Article III standing. Petitioner Initial Brief at 2732; Petitioner Reply Brief at 5-19. However, the North

Carolina Commission also expressly relied on its

special status as a State litigant to establish standing

under Massachusetts. Petitioner Initial Brief at

32-34; Petitioner Reply Brief at 19-21. The District

of Columbia Circuit dismissed the North Carolina

Commission’s appeal without acknowledging that argument or addressing Massachusetts. Pet. Appendix-A

at 1a-4a. That decision is in direct conflict with this

Court’s holding in Massachusetts.

Massachusetts held that “States are not normal

litigants for the purposes of invoking federal jurisdiction.” Massachusetts, 549 U.S. at 518. “It is of

considerable relevance that the party seeking review

here is a sovereign state and not, as it was in Lujan,

a private individual.” Id. The distinction between

State and private litigants is based on the fact that

States “surrender[ed] certain sovereign prerogatives”

when they entered the Union. Id. at 518-19. “These

sovereign prerogatives are now lodged in the Federal

Government” and, as such, states have standing to

protect their parens patriae interests where federal

law preempts them from exercising their once-sovereign abilities to protect the interests of their citizens.

Id. at 519, n.17. As such, Massachusetts requires that

courts afford State litigants special solicitude when

analyzing questions of standing. Id., at 518-20.

Like the petitioner in Massachusetts, North Carolina is a sovereign State that surrendered certain

sovereign prerogatives when it joined the Union, i.e.,

the ability to regulate the rates for, and construction

and operation of, pipeline facilities that are in North

Carolina but that are engaged in interstate commerce.

This Court recognizes that “the regulation of utilities

is one of the most important of the functions traditionally associated with the police power of the States.”

Ark. Elec. Coop. Corp. v. Ark. Pub. Serv. Comm’n, 461

U.S. 375, 377 (1983). By surrendering this important

function to the federal government, it is imperative

that North Carolina be afforded access to federal

courts to challenge FERC actions that harm North

Carolina’s quasi-sovereign and parens patriae interests in interstate natural gas pipeline facilities con-

structed and operated within its borders and rates

that North Carolina citizens pay for service on those

facilities.

In discussing the special solicitude to which State

litigants are entitled, Massachusetts emphasized that

the State litigant in that proceeding was afforded

a special procedural right to challenge the federal

agency action at issue there:

Given that procedural right [under the Clean

Air Act to challenge the rejection of a rulemaking petition as arbitrary and capricious]

and Massachusetts’ stake in protecting its

quasi-sovereign interests, the Commonwealth

is entitled to special solicitude in our standing

analysis . . . . [T]here is a critical difference

between allowing a State ‘to protect her

citizens from the operation of federal statutes’

(which is what Mellon prohibits) and allowing

a State to assert its rights under federal law

(which it has standing to do).

Id. at 520, n.17. Similarly, in Lujan, a case addressed

by Massachusetts, the Court discussed the important

role of procedural rights in standing inquiries.

There is this much truth to the assertion that

“procedural rights” are special: The person

who has been accorded a procedural right

to protect his concrete interests can assert

that right without meeting all the normal

standards for redressability and immediacy.

Lujan, 504 U.S. at n.7.

The Clean Air Act’s procedural right to challenge

unlawful agency action is substantially similar to the

procedural rights the Natural Gas Act affords to

States and State commissions to challenge FERC’s

actions. Under FERC’s implementing regulations,

State commissions are distinct from parties that must

seek, and be granted, leave before they can become a

party to FERC proceedings. See 18 C.F.R. § 385.214(a)(2)

(permitting State Commissions to intervene in proceedings as a matter of right, without motion), Pet.

Appendix-O at 364a-365a. Given its authority under

State law “to . . . appear before federal . . . courts and

agencies as in its opinion may be necessary to secure

for the users of public utility service in [North

Carolina] just and reasonable rates and service” (N.C.

Gen. Stat. § 62-48(a), Pet. Appendix-M at 360a), the

North Carolina Commission exercised this right and

intervened in the underlying certificate proceedings,

which implicated North Carolina’s quasi-sovereign and

parens patriae interests in interstate natural gas

pipeline facilities constructed and operated within its

borders and rates paid by North Carolina ratepayers

for service on those facilities. Pet. Appendix-B at 10a;

Pet. Appendix-D at 94a-95a; Pet. Appendix-F at 144a.

The Natural Gas Act also provides States procedural rights to challenge FERC orders. 15 U.S.C.

§§ 717r(a), (b), Pet. Appendix-I at 347a-349a. The

North Carolina Commission raised substantive concerns

with Transco’s proposals, arguing that they negatively

impacted North Carolina. Pet. Appendix-B at 10a18a; Pet. Appendix-D at 94a-96a; Pet. Appendix-F at

144a-145a. Aggrieved by the manner in which FERC’s

orders dismissed those challenges, the North Carolina

Commission invoked its procedural rights by seeking

rehearing and judicial review under 15 U.S.C. § 717r(a),

(b). Pet. Appendix-C at 81a-82a; Pet. Appendix-E at

130a-131a; Pet. Appendix-G at 275-282a.

The District of Columbia Circuit dismissed the North

Carolina Commission’s appeal without acknowledging

that argument or addressing Massachusetts’ and

Lujan’s discussion of the importance of concomitant

procedural rights. Pet. Appendix-A at 1a-4a. As such,

its decision is in direct conflict with Massachusetts

and Lujan. The effect of that erroneous decision is

significant. It deprives a State litigant of access to

federal courts to challenge federal agency actions that

impact the State’s quasi-sovereign and parens patriae

interests in interstate natural gas pipeline facilities

constructed and operated within its borders and rates

paid by North Carolina ratepayers for service on such

facilities.

B. In Reversing the District of Columbia

Circuit’s Dismissal of the North Carolina

Commission’s Appeal, the Court Should

Address the Split Among the Circuits

and Affirm the Scope and Durability of

Massachusetts’ Special Solicitude Doctrine

for State Litigants.

The courts of appeals interpret Massachusetts differently. For example, despite ignoring Massachusetts

altogether in the case below, the District of Columbia

Circuit narrowly construed Massachusetts in Center

for Biological Diversity v. Department of Interior,

563 F.3d 466, 476 (D.C. Cir. 2009), emphasizing

the “uniqueness” of Massachusetts. According to the

District of Columbia Circuit, Massachusetts “stands

only for the limited proposition that, where a harm is

widely shared, a sovereign, suing in its individual

interest, has standing to sue where that sovereign’s

individual interests are harmed, wholly apart from the

alleged general harm.” Id. at 477. In stark contrast,

the Fifth Circuit found it “obvious that being a state

greatly matters in the standing inquiry, and it makes

no difference . . . whether [that] means that states are

afforded a relaxed standing inquiry by virtue of their

statehood or whether their statehood, in [and] of itself,

helps confer standing.” Texas v. United States, 809

F.3d 134, n.26 (5th Cir. 2015), aff’d by an equally

divided Court, 136 S. Ct. 2271, 2272 (2016) (internal

quotations omitted).

Similar to the Fifth Circuit’s interpretation, but in

contrast to the District of Columbia Circuit’s narrow

interpretation in Centers for Biological Diversity,

District of Columbia Circuit Judge Brown opined that

“[S]tate litigants” are afforded “laxity” in the standing

analysis because “the [Supreme] Court lowered the

bar [in Massachusetts], ruling that state litigants were

‘entitled to special solicitude’” that “likely does not

extend to non-state litigants . . . who must clear the

ordinary hurdles to standing.” Arpaio v. Obama, 797

F.3d 11, 27 (D.C. Cir. 2015) (Brown, J., concurring).

The Second Circuit has grappled with how to interpret and apply Massachusetts. For example, it suggested that “the Massachusetts Court . . . arguably

muddled state proprietary and parens patriae standing.” Connecticut v. Am. Elec. Power Co., 582 F.3d 309,

337 (2d Cir. 2009), juris. aff’d by an equally divided

court, 131 S. Ct. 2527, 2535 (2011); see also id. at 338

(“The question is whether Massachusetts’ discussion of

state standing has an impact on the analysis of parens

patriae standing[.] That is, what is the role of

the Article III parens patriae standing in relation to

the test set out in Lujan?”). Despite acknowledging

“confusion” on Massachusetts’ impact on the analysis

of parens patriae standing, the District of Columbia

Circuit purports to know the answers to these

questions. See Gvt. Province of Manitoba v. David

Bernhardt, D.C. Cir. Case No. No. 17-5242, Slip Op.

at 13 (May 3, 2019) (“Massachusetts v. EPA is not a

parens patriae case.”). Notably, the Fifth Circuit’s

Texas v. United States decision did not rely on parens

patriae standing in affording special solicitude to the

State litigant.

As demonstrated above, this Petition raises a question of exceptional importance. Indeed, the Court has

twice granted petitions for certiorari that addressed

Massachusetts, splitting four-to-four both times. Texas

v. United States, 136 S. Ct. at 2272; Connecticut v.

Am. Elec. Power Co., 131 S. Ct. at 2535. This Petition

represents a unique opportunity to address this exceptional issue and provide critical clarity to State

litigants that may be denied access to federal courts in

circuits that construe Massachusetts narrowly. In that

regard, had the North Carolina Commission’s appeal

been addressed by the Fifth Circuit, instead of the

District of Columbia Circuit, it is likely that North

Carolina would not have been denied the ability

to challenge FERC orders that directly impact its

quasi-sovereign and parens patriae interests. Thus, in

addition to the importance of granting this Petition

and allowing North Carolina the ability to ensure

the federal government protects its interests, the

Court should grant this Petition to clarify and affirm

the scope and durability of Massachusetts’ special

solicitude doctrine for all State litigants.

CONCLUSION

The Petition for a writ of certiorari should be

granted for the foregoing reasons.

Respectfully submitted,

KATHLEEN L. MAZURE

Counsel of Record

JASON T. GRAY

DUNCAN & ALLEN

1730 Rhode Island Avenue, NW

Suite 700

Washington, DC 20036

(202) 289-8400

klm@duncanallen.com

jtg@duncanallen.com

Counsel for Petitioner

July 2, 2019

APPENDIX

APPENDIX A

UNITED STATES COURT OF APPEALS

FOR THE DISTRICT OF COLUMBIA CIRCUIT

[Filed: April 3, 2019]

————

No. 18-1018

————

NORTH CAROLINA UTILITIES COMMISSION,

Petitioner,

FEDERAL ENERGY REGULATORY COMMISSION,

Respondent,

PUBLIC SERVICE COMMISSION OF THE STATE OF

NEW YORK AND TRANSCONTINENTAL

GAS PIPE LINE COMPANY, LLC,

Intervenors.

————

Consolidated with 18-1019, 18-1020

————

On Petitions for Review of Orders of the

Federal Energy Regulatory Commission

————

September Term, 2018

————

Before: GARLAND, Chief Judge, and GRIFFITH and

WILKINS, Circuit Judges.

————

JUDGMENT

This appeal was considered on the record from the

Federal Energy Regulatory Commission (“FERC”) and

on the briefs of the parties and oral arguments of

counsel. The court has accorded the issues full consideration and has determined that they do not warrant

a published opinion. See D.C. CIR. R. 36(d). For the

reasons stated below, it is

ORDERED and ADJUDGED that the petition for

review be DISMISSED for lack of jurisdiction.

Petitioner North Carolina Utilities Commission

(“NCUC”) and Intervenor New York State Public

Service Commission (“NYSPSC”) ask this Court to

set aside three FERC orders granting certificates

to Transcontinental Gas Pipe Line Company, LLC

(“Transco”) to construct and operate interstate natural gas pipeline projects – the Virginia Southside

Expansion Project, the Dalton Expansion Project, and

the Atlantic Sunrise Project – in the Eastern United

States. NCUC and NYSPSC contend that the recourse

rate used in FERC’s certification orders relies on

an outdated and inflated pre-tax return. Thus, they

argue, the agreed-upon negotiated rate is tainted,

given FERC’s intention for recourse rates to constrain

a company’s ability to exercise market power during

rate negotiations.

The Natural Gas Act instructs that only “aggrieved”

persons may seek judicial review of a FERC order. 15

U.S.C. § 717r(b). “A party is aggrieved only ‘if it

can establish both the constitutional and prudential

requirements for standing.’” PNGTS Shipper’s Grp. v.

FERC, 592 F.3d 132, 136 (D.C. Cir. 2010) (quoting

Exxon Mobil Corp. v. FERC, 571 F.3d 1208, 1219 (D.C.

Cir. 2009)). The “irreducible constitutional minimum”

of standing requires that a petitioner allege an “an

injury in fact” that is “concrete and particularized” and

“actual or imminent, not conjectural or hypothetical.”

Lujan v. Defenders of Wildlife, 504 U.S. 555, 559-61

(1992). These standing requirements apply equally

to intervenors. Alabama Mun. Distributors Group. v.

FERC, 300 F.3d 877, 879 n.2 (D.C. Cir. 2002) (per

curiam).

Petitioner and Intervenor lack standing because

they have failed to provide sufficient evidence to

establish injury in fact. NCUC “assume[s]” that ratepayers in its state will use the facilities certificated

on the Atlantic Sunrise Project. Appellant’s Br. 31.

NYSPSC, through declaration from the Deputy

Director for Natural Gas and Water within the Office

of Electricity, Gas, and Water at the New York State

Department of Public Service, insists that the Atlantic

Sunrise’s project shippers will “almost certainly exercise

their contractual rights to use the expansion capacity

to ship at least some of their gas to New York.”

McCarran Declaration 7-8. But neither NCUC nor

NYSPSC has shown a “substantial probability” that

any capacity from the Atlantic Sunrise project will

flow into their respective states, nor have they shown

that any end-users in their states will pay higher rates

as a result of the project. Kansas Corp. Comm’n v.

FERC, 881 F.3d 924, 930 (D.C. Cir. 2018). Indeed, with

respect to the Dalton Expansion or Virginia Southside

Expansion Projects, they offer no evidence of injury.

Any harm is therefore either non-existent or “conjectural or hypothetical,” which does not suffice to

demonstrate injury in fact. Id.

Pursuant to D.C. Circuit Rule 36, this disposition

will not be published. The Clerk is directed to withhold

issuance of the mandate herein until seven days after

resolution of any timely petition for rehearing or

petition for rehearing en banc. See FED. R. APP. P.

41(b); D.C. CIR. R. 41.

Per Curiam

FOR THE COURT:

Mark J. Langer, Clerk

BY:

/s/

Scott H. Atchue

Deputy Clerk

APPENDIX B

156 FERC ¶ 61,092

UNITED STATES OF AMERICA

FEDERAL ENERGY REGULATORY COMMISSION

Docket No. CP15-117-000

Before Commissioners: Norman C. Bay, Chairman;

Cheryl A. LaFleur, Tony Clark,

and Colette D. Honorable.

Transcontinental Gas Pipe Line Company, LLC

ORDER ISSUING CERTIFICATE

(Issued August 3, 2016)

1. On March 19, 2015, Transcontinental Gas Pipe

Line Company, LLC (Transco) filed an application

pursuant to section 7(c) of the Natural Gas Act (NGA)1

and Part 157 of the Commission’s regulations for a

certificate of public convenience and necessity authorizing it to construct, lease, and operate pipeline,

compression, metering, and appurtenant facilities in

Virginia, North Carolina, and Georgia (Dalton Expansion

Project). As discussed below, the Commission will grant

the requested authorizations, subject to conditions.

I. Background and Proposal

A. Construction of Facilities

2. Transco is a natural gas company, as defined by

section 2(6) of the NGA,2 which transports natural gas

in interstate commerce. Transco’s natural gas transmission system extends through Texas, Louisiana, the

offshore Gulf of Mexico area, Mississippi, Alabama,

15 U.S.C. § 717f(c) (2012).

Id. § 717a(6).

Georgia, South Carolina, North Carolina, Virginia,

Maryland, Pennsylvania, and New Jersey, to its

termini in the New York City metropolitan area.

3. Transco proposes to construct and operate

approximately 114.99 miles of 30-, 24-, 20-, and 16inch diameter pipeline (Dalton Lateral), three meter

stations, and one compressor station (Compressor

Station 116) in Georgia, as well as valves, yard piping,

and other appurtenant facilities in Virginia and North

Carolina. Specifically, Transco proposes to construct

and operate:

• Dalton Lateral Segment 1 – Approximately 7.6

miles of 30-inch-diameter pipeline in Coweta

and Carroll Counties, Georgia, from the discharge of the existing Compressor Station 115

to the proposed Compressor Station 116;

• Dalton Lateral Segment 2 – Approximately 51.3

miles of 24-inch-diameter pipeline in Carroll,

Douglas, Paulding, and Bartow Counties, Georgia,

from the discharge of proposed Compressor

Station 116 to the proposed Beasley Road Meter

Station;

• Dalton Lateral Segment 3 – Approximately 53.8

miles of 20-inch-diameter pipeline in Bartow,

Gordon, Murray, and Whitfield Counties, Georgia,

from the proposed Beasley Road Meter Station

to the proposed Looper Bridge Road Meter

Station;

• AGL Spur Lateral – Approximately 2.0 miles of

16-inch-diameter pipeline in Murray County,

Georgia, from milepost (MP) 105.2 of the Dalton

Lateral to the proposed Murray Meter Station;

• Beasley Road Meter Station (formally known

as the AGL-Bartow Meter Station) – a new

190,000 dekatherms (Dth) per day meter

station in Bartow County, Georgia;

• Looper Bridge Road Meter Station (formally

known as the Oglethorpe-Smith Meter Station) – a new 208,000 Dth per day meter station

in Murray County, Georgia;

• Murray Meter Station (formally known as the

AGL-Murray Meter Station) – a new 50,000 Dth

per day meter station in Murray County,

Georgia;

• Compressor Station 116 – a new 21,830 horsepower compressor station in Carroll County,

Georgia, with two Solar Taurus 70 gas turbine

driven compressor units near MP 7.6 on the

Dalton Lateral;

• Valves and yard piping for south flow compression at Compressor Stations 165 in Pittsylvania

County, Virginia, and 180 in Prince William

County, Virginia;

• Odor masking/deodorization of valves at valve

sites between Compressor Stations 160 in

Rockingham County, North Carolina, and 165

in Pittsylvania County, Virginia;

• Odor detection and supplemental odorization

at 20 delivery meters on the South Virginia

Lateral and between Compressor Stations 160

and 165 in Rockingham, Northampton and

Hertford Counties, North Carolina, and

Pittsylvania, Brunswick, Mecklenburg, Halifax,

and Greensville Counties, Virginia;

• Valve site masking/deodorization at Compressor

Station 167 in Mecklenburg County, Virginia;

and

• Related appurtenant underground and aboveground facilities.

4. Transco states that the proposed project will

enable it to provide 448,000 Dth per day of incremental firm transportation service from a receipt point in

Zone 6 on its mainline in Mercer County, New Jersey,

for delivery to an interconnection with Gulf South

Pipeline Company, LP in Pike County, Mississippi,

and to interconnections in northwest Georgia through

the proposed Dalton Lateral.

5. Transco held an open season from May 30

through June 28, 2012. As a result of the open season,

Transco executed binding precedent agreements with

Atlanta Gas Light Company (Atlanta Gas Light or

AGL) and Oglethorpe Power Corporation (Oglethorpe)

for 240,000 and 208,000 Dth per day of firm transportation service, respectively, for 25 years. This

represents all of the capacity associated with the

proposed Dalton Expansion Project.

6. The project’s estimated cost is approximately

$471.9 million. Transco states that it will undertake

permanent financing at a later date as part of its

overall, long-term financing program. Transco has proposed an incremental recourse reservation rate for

firm transportation service on the project facilities,

as described in more detail below. Atlanta Gas Light

and Oglethorpe have agreed to pay a negotiated rate.

Transco will provide service under the terms and

conditions of its existing Rate Schedule FT.

B. Lease of Facilities

7. Transco and Dogwood Enterprise Holdings, Inc.

(Dogwood) will jointly own the Dalton Lateral, as

tenants in common, with each holding a 50 percent

undivided ownership interest.3 Dogwood will hold its

50 percent ownership interest as a “passive owner” of

the lateral. On the in-service date of the Dalton

Lateral, Dogwood will lease its ownership interest in

the lateral, including its share of the capacity rights,

to Transco, which will have full possessory, operational, and capacity rights.

8. The lease agreement provides that Dogwood and

Transco will jointly fund the cost to construct the

Dalton Lateral facilities in proportion to their respective ownership interests. Transco is the sole applicant

for the NGA section 7(c) certificate to construct and

operate the Dalton Lateral, as Dogwood is not currently an NGA jurisdictional entity and does not

intend to become one as part of the Dalton Lateral

ownership structure.

II. Notice, Interventions, and Procedural Issues

9. Notice of Transco’s application was published in

the Federal Register on April 10, 2015 (80 Fed. Reg.

19,312). The parties listed in Appendix A filed timely,

unopposed motions to intervene.4

10. The parties listed in Appendix B filed late

motions to intervene. We will grant the late-filed

motions to intervene, since to do so at this stage of the

Dogwood is an affiliate of AGL Resources, the parent

company of Atlanta Gas Light.

Timely, unopposed motions to intervene are granted by

operation of Rule 214 of the Commission’s Rules of Practice and

Procedure. See 18 C.F.R. § 385.214 (2015).

10a

proceeding will not delay, disrupt, or unfairly prejudice the proceeding or other parties.5

11. The North Carolina Utilities Commission and

the New York State Public Service Commission (State

Commissions) filed a joint protest to Transco’s application. Transco filed an answer to the State Commissions’

protest and the State Commissions filed an answer to

Transco’s answer. Although the Commission’s Rules of

Practice and Procedure do not permit answers to

protests or answers to answers, the Commission finds

good cause to waive its rules and accept the answers

because they provide information that has assisted in

our decision making process.6

12. The Bartow County School System and Bartow

County Board of Education (Bartow), the 1460

Partnership, LLLP (1460 Partnership), and the

State Commissions request an evidentiary hearing.

Specifically, Bartow seeks a hearing on issues regarding the route of the Dalton Lateral, claiming that the

pipeline is proposed to be located at an unsafe distance

from two elementary schools and that the pipeline’s

proposed location will interfere with its ability to

expand the schools on land that it specifically acquired

for that purpose. The 1460 Partnership seeks a

hearing on the route of the lateral across the Pole Cat

Creek Farms, over which it has a fee simple property

interest.7 The State Commissions seek a hearing on

(1) Transco’s use of a 15.34 percent pre-tax rate of

See 18 C.F.R. § 385.214(c)(2) (2015).

Id. § 385.213(a)(2).

The Pole Cat Creek Farms is an undeveloped tract of land,

consisting of 360 acres of forest wetland, freshwater lake, and

field meadow. The 1460 Partnership states that the tract is home

to more than 50 types of plants and 150 types of animals.

11a

return in developing its proposed recourse rates and

(2) whether the project is being subsidized by prior

expansions that created southbound capacity on Transco’s

mainline. The State Commissions also request that we

partially consolidate this proceeding with Transco’s

proposals to construct and operate the Virginia

Southside Expansion Project II8 and the Atlantic

Sunrise Project9 in order to address issues about

Transco’s pre-tax rate of return.

13. Although our regulations provide for a hearing,

neither section 7 of the NGA nor our regulations

require that such hearing be a trial-type evidentiary

hearing.10 When, as is usually the case, the written

record provides a sufficient basis for resolving the

relevant issues, it is our practice to provide for a paper

hearing.11 That is the case here. We have reviewed the

In the Virginia Southside Expansion Project II, Transco was

authorized to construct and operate approximately 4.33 miles of

pipeline and compression facilities. See Transcontinental Gas

Pipeline Co., LLC, 156 FERC ¶ 61,022 (2016).

In the Atlantic Sunrise Project, Docket No. CP15-138-000,

Transco proposes to construct and operate approximately 57.3

miles of 30-inch-diameter pipeline and 125.2 miles of 42-inchdiameter pipeline in Pennsylvania.

See Minisink Residents for Environmental Preservation

and Safety v. FERC, 762 F.3d 97, 114 (D.C. Cir. 2014) (“FERC’s

choice whether to hold an evidentiary hearing is generally

discretionary.”).

See NE Hub Partners, L.P., 83 FERC ¶ 61,043, at 61,192

(1998), reh’g denied, 90 FERC ¶ 61,142 (2000); Pine Needle LNG

Co., LLC, 77 FERC ¶ 61,229, at 61,916 (1996). Moreover, courts

have recognized that even where there are disputed issues the

Commission need not conduct an evidentiary hearing if the

disputed issues “may be adequately resolved on the written

record.” Minisink Residents, 762 F.3d at 114 (quoting Cajun Elec.

Power Coop., Inc. v. FERC, 28 F.3d 173, 177 (D.C. Cir. 1994)).

12a

requests for an evidentiary hearing by Bartow, the

1460 Partnership, and the State Commissions and

conclude that all issues of material fact relating to

Transco’s proposal are capable of being resolved on the

basis of the written record. Accordingly, we will deny

the requests for a formal hearing. As to the State

Commissions’ request for partial consolidation, the

Commission’s policy is to consolidate matters only if a

trial-type evidentiary hearing is required to resolve

common issues of law and fact and consolidation will

ultimately result in greater administrative efficiency.12

Since there is no need for an evidentiary hearing in

this proceeding, we will deny the State Commissions’

request for partial consolidation.

14. The Natural Gas Supply Association, Atlanta

Gas Light, and Oglethorpe filed comments supporting

the project. Numerous other parties filed comments

regarding the routing of the Dalton Lateral, safety,

sufficiency of information, and potential aesthetic,

economic, and environmental impacts of the proposal.

The concerns raised in the State Commissions’ protest

and in the comments by the other parties are addressed

below or in the Environmental Assessment (EA).

III. Discussion

15. Since Transco proposes to construct and operate

facilities used to transport natural gas in interstate

commerce subject to the jurisdiction of the Commission,

See Columbia Gulf Transmission Co., 139 FERC ¶ 61,236, at

P 20 (2012); Midcontinent Express Pipeline LLC, 124 FERC

¶ 61,089, at P 27 (2008); Startrans IO, L.L.C., 122 FERC ¶ 61,253,

at P 25 (2008); see also Mobil Oil Explor. & Prod. Serv. v. United

Distrib. Cos., 498 U.S. 211, 230-31 (1991) (agencies “enjoy[] broad

discretion” in determining how best to order its proceedings).

13a

the proposal is subject to the requirements of subsections (c) and (e) of section 7 of the NGA.13

A. Certificate Policy Statement

16. The Certificate Policy Statement provides guidance for evaluating proposals for new construction.14

The Certificate Policy Statement establishes 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.

17. 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 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

15 U.S.C. §§ 717f(c) and (e) (2012).

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).

14a

the market and their captive customers, or landowners and communities affected by the construction. 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 proceed to complete the environmental analysis where other interests are considered.

18. As discussed above, the threshold requirement

for a new project is that the applicant must be

prepared to financially support the project without

relying on subsidization from its existing customers.

The Commission has determined that, in general,

where a pipeline proposes an incremental recourse

rate for the project – as Transco does here – the

pipeline satisfies the threshold requirement that the

project will not be subsidized by existing shippers.15

Because Transco proposes to charge an incremental

rate for the services proposed in this proceeding that,

as discussed below, exceeds the existing applicable

system rate, we find that the threshold no-subsidy

requirement under the Certificate Policy Statement

has been met.

19. The State Commissions assert that Transco has

not addressed the possibility that the proposed project

will be subsidized by shippers on Transco’s recentlyapproved Leidy Southeast Project in Pennsylvania,

which has a higher recourse rate than the incremental

recourse rate proposed for this project. The bulk of the

See, e.g., Dominion Transmission, Inc., 155 FERC ¶ 61,106

(2016).

15a

Leidy Southeast facilities are upstream of the proposed Dalton facilities and transport gas from receipt

points on Transco’s Leidy Line to Transco’s mainline.

We find that the Leidy Southeast facilities are not

integral to the provision of the proposed Dalton

Expansion Project services. The two projects’ transportation paths and facilities are too dissimilar for

subsidization to be a concern. Thus we find that

existing Leidy Southeast Project shippers will not

subsidize the Dalton Expansion Project shippers.

20. Transco has designed the Dalton Expansion

Project to ensure that there will not be any adverse

impacts on its existing shippers. With respect to other

pipeline’s customers, there will be no adverse impact

on other pipelines in the region or their captive

customers because the Project is not intended to

replace service on other pipelines. Also, no pipeline

company or their captive customers have protested

Transco’s application.

21. Regarding effects on landowners and communities, the proposed Dalton Expansion Project will disturb approximately 1,764 acres of land during construction and about 746.3 acres during operation.

To minimize impacts on landowners, Transco will

collocate approximately 49 percent of the proposed

pipeline facilities with existing rights-of-way and on

previously disturbed property. The modifications to

existing compressor stations will take place within the

fence lines of those existing facilities. Accordingly, we

find that Transco has designed the project to minimize

adverse impacts on landowners and surrounding

communities.

22. Transco has entered into binding precedent

agreements for 25 years with Atlanta Gas Light and

Oglethorpe, which fully subscribe the project. Based

16a

on the benefits the project will provide16 and the

minimal adverse impacts on existing shippers, other

pipelines and their captive customers, and landowners

and surrounding communities, we find, consistent

with the Certificate Policy Statement and NGA section

7(c), that the public convenience and necessity

requires approval of Transco’s proposal, subject to the

conditions discussed below.

B. Rates

1. Pre-tax Rate of Return

23. In their protest, the State Commissions take

issue with Transco’s proposed use of a pre-tax return

of 15.34 percent in calculating its proposed incremental recourse rates in its applications for its Dalton

Expansion Project proposal in this proceeding, as

well as in its recently approved Virginia Southside

Expansion II Project in Docket No. CP15-118-000, and

its proposed Atlantic Sunrise Project in Docket No.

CP15-138-000. The State Commissions acknowledge

that Transco’s use of the specified pre-tax return most

recently approved in a section 4 rate case is consistent

with Commission policy, but they emphasize that

that rate case was fifteen years ago. They argue the

incremental recourse rates approved in the current

proceedings should take into account the significant

changes in financial markets since then.17 The State

The shippers state that Commission approval of Transco’s

application will provide more diversified natural gas supply

options (Oglethorpe intervention at 2 and comments in support

of the EA at 2) and enable Atlanta Gas Light to meet growing

customer demands in Georgia (Atlanta Gas Light intervention at

2 and June 10, 2016 support letter at 2).

Transco’s last section 4 rate case in which a specified rate of

return was used in calculating Commission-approved rates was

in Docket No. RP01-245-000, et al. A letter order issued in that

17a

Commissions assert that the pre-tax return of 15.34

percent accounts for approximately half of Transco’s

proposed cost of service in these proceedings,18 and

their comments included a discounted cash flow (DCF)

analysis, which they contend reflects current market

conditions and reflects a median rate of return on

equity (ROE) of 10.95 percent for natural gas pipelines.19 They request partial consolidation of these

proceedings to consider the appropriate pre-tax return

in a full evidentiary hearing.

24. As the State Commissions argued in the recent

proceeding regarding Transco’s Virginia Southside

Expansion II Project,20 recent Commission orders

provide valuable perspective indicating that Transco’s

proposed 15.34 percent pre-tax return is not reasonable. They reference the 2015 order where the Commission relied on a DCF analysis for a proxy group of

pipelines based on a six-month period ending March

31, 2011, to limit Portland Natural Gas Transmission

System’s ROE to 11.59 percent, the top of the range of

reasonable returns for which the median ROE was

10.28 percent.21 The State Commissions also point to

docket on July 23, 2002, accepted a partial settlement resolving

cost classification, cost allocation, and rate design subject to

certain reservations and adjustments, and revising Transco’s

generally applicable rates. Transcontinental Gas Pipe Line Corp.,

100 FERC ¶ 61,085, at P 2 (2002).

State Commissions’ April 22, 2015 Protest in Docket No.

CP15-117-000, et al.

Preliminary Pipeline DCF Analysis Exhibit to State Commissions’ Protest.

Transcontinental Gas Pipeline Co., LLC, 156 FERC ¶ 61,022,

at PP 23-26 (2016).

Portland Natural Gas Transmission System, Opinion No.

524-A, 150 FERC ¶ 61,107, at P 195 (2015).

18a

the Commission’s 2013 orders that limited the ROEs

for El Paso Natural Gas Company, L.L.C. and Kern

River Gas Transmission Company to 10.5 percent and

11.55 percent, respectively.22

25. Transco’s answer emphasizes that this proceeding and the proceedings on its proposed Virginia

Southside Expansion II and Atlantic Sunrise projects

are section 7 certificate proceedings, not section 4 rate

cases, and that its proposed recourse rates in these

certificate proceedings will be initial section 7 rates for

incremental services using new expansion capacity.

Transco further asserts its proposed initial section 7

recourse rates are consistent with Commission policy

in section 7 proceedings, in that they are appropriately

designed to recover each project’s incremental cost of

service.23 In the State Commissions’ answer to Transco’s

answer, they contend that when the Commission grants

a pipeline negotiated rate authority, it relies on the

availability of cost-based recourse rates to prevent the

pipeline from exercising market power by ensuring

that shippers will have the option of choosing to pay

cost-based recourse rates for expansion capacity that

becomes available on either an interruptible or firm

El Paso Natural Gas Co., L.L.C., Opinion No. 528, 145

FERC ¶ 61,040, at P 686 (2013); Kern River Gas Transmission

Co., Opinion No. 486-F, 142 FERC ¶ 61,132, at P 263 (2013).

Transco cites the Commission’s order that certificated its

Rock Springs Lateral and additional mainline compression to

provide service for another new electric generating plant. In that

order, the Commission approved Transco’s proposed incremental

recourse rate for that expansion capacity, which was calculated

using the pre-tax return of 15.34 percent from its settlement

rates in Docket No. RP01-245. Transcontinental Gas Pipe Line

Co., LLC, 150 FERC ¶ 61,205, at P 17 (2015).

19a

basis. Therefore, the State Commissions assert that

even if a pipeline has negotiated rate agreements for

all of the expansion capacity proposed in a certificate

proceeding, the recourse rates nevertheless need to be

properly designed and based on a reasonable estimate

of the actual costs to construct and operate the

expansion capacity.

26. The State Commissions are correct that “the

predicate for permitting a pipeline to charge a negotiated rate is that capacity is available at the recourse

rate,”25 and the Commission therefore requires that

shippers have the option of choosing to pay a costbased recourse rate for expansion capacity that

becomes available. However, as the State Commissions acknowledge, the Commission’s consistent policy

in section 7 certificate proceedings is to require that a

pipeline’s cost-based recourse rates for incrementallypriced expansion capacity be designed using the rate

of return from its most recent general rate case

approved by the Commission under section 4 of the

NGA in which a specified rate of return was used to

calculate the rates.26 Transco’s proposed incremental

State Commissions’ May 27, 2015 Answer at 2 (citing

Alternatives to Traditional Cost-of-Service Ratemaking, 74 FERC

¶ 61,076).

Columbia Gas Transmission Corp., 97 FERC ¶ 61,221, at

62,004 (2001) (citing Alternatives to Traditional Cost-of-Service

Ratemaking for Natural Gas Pipelines; Regulation of Negotiated

Transportation Services of Natural Gas Pipelines, 74 FERC

¶ 61,076).

See, e.g., Trunkline Gas Co., LLC, 135 FERC ¶ 61,019, at

P 33 (2011); Florida Gas Transmission Co., LLC, 132 FERC

¶ 61,040, at P 35 & n.12 (2010); Northwest Pipeline Corp., 98

FERC ¶ 61,352, at 62,499 (2002); and Mojave Pipeline Co., 69

FERC ¶ 61,244, at 61,925 (1994). See also Dominion Cove Point

LNG, LP, 115 FERC ¶ 61,337, at P 132 (2006), order on reh’g, 118

20a

recourse rate for the Dalton Expansion Project is

based on the specified pre-tax return of 15.34 percent

underlying the design of its approved settlement rates

in Docket No. RP01-245-000, et al.27 Since Transco’s

most recently approved general section 4 rate case

settlements in Docket Nos. RP12-993-000, et al.28 and

RP06-569-004, et al.29 were both “black box” settle-

FERC ¶ 61,007, at PP 120 & 122-123 (2007) (allowing, on

rehearing, Dominion Cove Point LNG to recalculate incremental

rates using the rates of return ultimately approved in its pending

rate case, as opposed to its proposed rates of return). If a

pipeline’s most recent general section 4 rate case involved a

settlement that did not specify a rate of return or pre-tax return,

the Commission’s policy requires that incremental rates in the

pipeline’s certificate proceedings be calculated using the rate of

return or pre-tax return from its most recent general section 4

rate case (or rate case settlement) in which a specified return

component was used to calculate the approved rates. See, e.g.,

Equitrans, L.P., 117 FERC ¶ 61,184, at P 38 (2006). This policy

applies even if a pipeline calculated its proposed incremental

rates for expansion capacity using a rate of return lower than the

most recently approved specified rate of return. Id. (rejecting

Equitrans’ proposed use of 14.25 percent ROE component for

incremental rates for mainline extension and requiring

recalculation using the specified pre-tax rate of return of 15

percent that was approved in its rate case).

Transcontinental Gas Pipe Line Corp., 100 FERC ¶ 61,085.

Transcontinental Gas Pipe Line Co., LLC, 144 FERC

¶ 63,029, at P 13 (2013) (certifying to the Commission an

uncontested settlement in which, “[w]ith the exception of certain

expressly designated items, the cost of service agreement was

reached on a ‘black box’ basis”); Transcontinental Gas Pipeline

Co., LLC, 145 FERC ¶ 61,205 (2013) (approving and accepting

tariff records to implement rate case settlement).

Transcontinental Gas Pipe Line Corp., 122 FERC ¶ 61,213

(2008) (approving and accepting tariff records to implement rate

case settlement); Transcontinental Gas Pipe Line Co., LLC, 147

FERC ¶ 61,102, at P 53 (2014) (explaining that the settlement

21a

ments that did not specify the rate of return or most

other cost of service components used to calculate

the settlement rates, Transco calculated its proposed

incremental rates in this certificate proceeding consistent with Commission policy by using the last

Commission-approved specified pre-tax return of

15.34 percent from its prior rate proceeding in Docket

No. RP01-245.

27. Further, in section 7 certificate proceedings the

Commission reviews initial rates for service using

proposed new pipeline capacity under the public convenience and necessity standard, which is a less

rigorous standard than the just and reasonable standard under NGA sections 4 and 5.30 The Commission

reached in Docket No. RP06-569 was a “black box” settlement

that did not specify a rate of return).

Atlantic Refining Co. v. Public Serv. Comm’n of New York,

360 U.S. 378 (1959) (CATCO). In CATCO, the Court contrasted

the Commission’s authority under sections 4 and 5 of the NGA to

approve changes to existing rates using existing facilities and its

authority under section 7 to approve initial rates for new services

and services using new facilities. The Court recognized “the

inordinate delay” that can be associated with a full-evidentiary

rate proceeding and concluded that was the reason why, unlike

sections 4 and 5, section 7 does not require the Commission to

make a determination that an applicant’s proposed initial rates

are or will be just and reasonable before the Commission

certificates new facilities, expansion capacity, and/or services. Id.

at 390. The Court stressed that in deciding under section 7(c)

whether proposed new facilities or services are required by the

public convenience and necessity, the Commission is required to

“evaluate all factors bearing on the public interest,” and an

applicant’s proposed initial rates are not “the only factor bearing

on the public convenience and necessity.” Id. at 391. Thus, as

explained by the Court, “[t]he Congress, in § 7(e), has authorized

the Commission to condition certificates in such manner as

the public convenience and necessity may require when the

Commission exercises authority under section 7,” id., and the

22a

develops the recourse rate for expansion capacity

based on the pipeline’s estimated cost of service. As

discussed above, the State Commissions’ protest

included a DCF analysis for natural gas pipelines,

which they contend reflects current market conditions

and a median ROE of 10.95 percent. However, the

Commission does not believe that conducting DCF

analysis in individual certificate proceedings would be

the most effective or efficient way for determining the

appropriate ROEs for proposed pipeline expansions.

While parties have the opportunity in section 4 rate

proceedings to file and examine testimony with regard

to the composition of the proxy group to use in the DCF

analysis, the growth rates used in the analysis, and

the pipeline’s position within the zone of reasonableness with regard to risk, it would be difficult, if

not impossible, to complete this type of analysis in

section 7 certificate proceedings in a timely manner

and attempting to do so would unnecessarily delay

proposed projects with time sensitive in-service schedules. The Commission’s current policy of calculating

incremental rates for expansion capacity using the

Commission-approved ROEs underling pipelines’ existing rates is an appropriate exercise of its discretion

in section 7 certificate proceedings to approve initial

rates that will “hold the line” until just and reasonable

rates are adjudicated under section 4 or 5 of the NGA.

28. Here, Transco is required to file an NGA general

section 4 rate case by August 31, 2018, pursuant to the

comeback provision in Article 6 of the settlement in

Commission therefore has the discretion in section 7 certificate

proceedings to approve initial rates that will “hold the line” and

“ensure that the consuming public may be protected” while

awaiting adjudication of just and reasonable rates under the

more time-consuming ratemaking sections of the NGA. Id. at 392.

23a

Docket No. RP12-993. Parties in that future rate case

will have an opportunity to review Transco’s pre-tax

return and other cost of service components. In

addition, given the possibility that that rate case could

result in another settlement for rates that are not

based on a specified rate of return and, as discussed

above, the Commission’s policy in section 7 certificate

proceedings is to require that a pipeline’s initial

rates for expansion capacity be designed using a

Commission-approved, specified rate of return, the

Commission would advise that parties in the rate case

use that opportunity to address issues of concern

relating to the rate of return that should be used in

calculating initial rates in Transco’s future certificate

proceedings.32

29. For the reasons discussed above, and consistent

with the rate of return accepted for the Virginia

Southside Expansion II Project,33 the Commission

finds that it is appropriate to apply its general policy

and accepts Transco’s use of a pre-tax return of 15.34

percent to calculate Transco’s initial recourse rate in

this proceeding. Parties should raise, in Transco’s

upcoming general rate case, any issues and concerns

they have regarding the rate of return or other cost of

service components to be used in calculating Transco’s

recourse rates in subsequent certificate proceedings.

Transcontinental Gas Pipe Line Co., LLC, 144 FERC

¶ 63,029.

See, e.g., Eastern Shore Natural Gas Co., 138 FERC ¶ 61,050

(2012) (approving settlement that established rates on “black

box” basis but provided a specified pre-tax rate of return).

Transcontinental Gas Pipeline Co., 156 FERC ¶ 61,022 at

P 26.

24a

2. Initial Rates

30. Transco proposes an initial incremental recourse

reservation charge of $0.50580 per Dth/day under its

existing Rate Schedule FT for service on the project.

In support of the proposed initial rates, Transco submitted an incremental cost of service and rate design

study showing the derivation of the recourse rate

under the project based on a total first year cost of

service of $82,708,551 and billing determinants of

448,000 Dth/day.34 The proposed cost of service is

based on a pre-tax rate of return of 15.34 percent, and

Transco’s system depreciation rates of 2.61 percent

for onshore transmission facilities, including negative

salvage, and 4.97 percent for solar turbines.35 The

proposed cost of service also includes the lease payments to Dogwood at an annualized amount equal to

approximately $25,691,000.

31. On October 29, 2015, the Commission issued a

data request directing Transco to provide a breakdown

of its Operation and Maintenance (O&M) expenses by

FERC account number and labor and non-labor costs

for the project. In response, Transco identified a total

of $357,883 in non-labor O&M costs in Account Nos.

853 and 864.36 These non-labor costs are classified as

variable costs, and section 284.7(e) of the Commission’s regulations does not allow variable costs to be

recovered through the reservation charge.37 Therefore,

See Transco’s Application at Exhibit P.

See Transcontinental Gas Pipe Line Co., LLC, 145 FERC

¶ 61,205, which established the current system depreciation rate

and the current negative salvage rate.

Transco’s November 2, 2015 Data Response, Response No. 1

and Schedule 1.

18 C.F.R. § 284.7(e) (2015).

25a

Transco must recalculate its incremental recourse

reservation rate to reflect the removal of variable costs.

32. Transco’s proposed incremental reservation charge

of $0.50590 per Dth/day is higher than the currently

applicable Rate Schedule FT Zone 6-4 reservation

charge of $0.41704 per Dth/day. We do not expect

that recalculation of the proposed rate to remove the

variable costs identified above will result in an incremental rate that is lower than the existing system

rate. Accordingly, because an appropriately calculated

incremental reservation charge will be higher than the

currently applicable Rate Schedule FT reservation

charge, the Commission will require use of the recalculated incremental reservation charge as the initial

recourse reservation charge for firm service using the

expansion capacity.38

33. Transco did not propose an incremental usage

charge since its initial filing included no variable costs.

An incremental usage charge calculated to recover

the $357,883 in variable costs would be lower than

the currently applicable Rate Schedule FT Zone 6-4

usage charge of $0.02375 per Dth. Therefore, the

Commission will require Transco to charge its currently applicable Rate Schedule FT usage charge for

the project.

34. Transco’s application does not address recourse

rates for interruptible service using the expansion

capacity. Consistent with Commission policy, the Commission will require Transco to charge its currently

Under the Certificate Policy Statement there is a presumption that incremental rates should be charged for proposed

expansion capacity if the incremental rate will exceed the

maximum system-wide rate. Certificate Policy Statement, 88

FERC at 61,745.

26a

effective system interruptible rates for interruptible

service using the expansion capacity.39

35. Transco states that Atlanta Gas Light Company

and Oglethorpe have elected to enter into negotiated

rate agreements for their capacity. Transco states that

it will file the negotiated rate agreements prior to the

commencement of service as required by Commission

policy.40

3. Fuel Retention and Electric Power Rates

36. Transco proposes to charge its generally applicable system fuel retention and electric power rates for

service on the project. Transco states that the project

facilities will reduce overall system fuel use (gas fuel

consumption plus the gas equivalent of electric power

consumption) to the benefit of non-project shippers.41

Transco’s fuel study shows that the project impact

of fuel consumption will result in a 30.53 percent

reduction in system fuel use attributable to existing

shippers.42 In view of this, we will approve Transco’s

proposal to charge its generally applicable system gas

See, e.g., Trunkline Gas Co., LLC, 153 FERC ¶ 61,300, at

P 62 (2015).

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. See, e.g., Texas

Eastern Transmission, LP, 149 FERC ¶ 61,198, at P 33 (2014).

See Transco’s Application at 11, Exhibit Z-1.

Transco’s study was based on ten representative days

between November 1, 2013 and October 31, 2014. Transco states

that the system was modeled with and without the incremental

project facilities and transportation volumes. See Transco’s

Application at Exhibit Z-1.

27a

fuel and electric power rates for service using the

expansion capacity.

4. Inexpensive Expansibility

37. The State Commissions assert that Transco’s

application appears to be deficient because it fails to

address the issue of inexpensive expansibility (i.e.,

whether it was possible to construct the Dalton Expansion Project at a lower cost because of the previous

construction of the Leidy Southeast Project). The State

Commissions claim that the Dalton Expansion Project

allows shippers to transport gas on Transco’s mainline

from New Jersey to Mississippi, but not pay for any

major facilities north of Georgia, which they contend

raises the question of whether this project will be

subsidized by shippers on prior expansions that created southbound capacity on Transco’s mainline. The

State Commissions note that the proposed $0.50580

recourse rate for the Dalton Expansion Project is

significantly lower than the estimated recourse rate of

$0.67393 for Leidy Southeast Project, which will

enable shippers to transport gas from receipt points

on Transco’s Leidy Line in Pennsylvania to various

delivery points along Transco’s mainline as far south

as Transco’s existing Station 85 Zone 4 and 4A pooling

points in Choctaw County, Alabama. Thus, the State

Commissions argue the new Dalton Expansion Project

will allow shippers to transport gas further south on

Transco’s mainline at a lower recourse rate than the

Leidy Southeast Project shippers.

38. Transco states that the inexpensive expansibility doctrine has no application to the Dalton and Leidy

Southeast Projects. Transco states that the Leidy

Southeast Project involves construction of extensive

looping and compression on Transco’s Leidy Line. In

contrast, the Dalton Expansion Project principally

28a

involves the construction of a new, 111-mile lateral

off the Transco mainline in Georgia. Transco states

that the bulk of the Leidy Southeast Project costs are

for facilities upstream of the point where the Dalton

capacity commences, and include pipeline looping

and compressor station horsepower additions on the

Leidy Line necessary to transport gas from the Leidy

Southeast receipt points on the Leidy Line to the

point of interconnection between the Leidy Line and

Transco’s mainline. Thus, Transco asserts that the

Leidy Southeast Project facilities do not beneficially

affect the facility costs underlying the Dalton Expansion

Project. Transco concludes that the primary firm capacity

paths and facilities under the two projects are too dissimilar to consider a roll-in of the costs of the projects.

39. The Commission disagrees with the State

Commissions that the Dalton Expansion Project is a

result of inexpensive expansibility made possible by

the Leidy Southeast Project. As Transco correctly

stated, the bulk of the Leidy Southeast Project are

facilities upstream of the point where the Dalton

capacity commences and were constructed to enable

delivery of gas from Transco’s Leidy Line to Transco’s

mainline. Conversely, the Dalton Expansion Project

transports gas from Transco’s Station 210 Zone 6

Pooling Point in Mercer County, New Jersey, and

transportation of the volumes entering this pool are

not dependent on the Leidy Southeast Project being

constructed. Due to the nature of pipeline construction, service on almost all incremental expansions use

some part of the existing pipeline system to provide

service, since expansion volumes can often be delivered by constructing discrete facilities in key areas to

alleviate bottlenecks or increasing throughput by

adding looping or compression. Thus, as we have here,

the Commission addresses concerns about potential

29a

subsidization by comparing the rate calculated to

recover the costs associated with the proposed expansion capacity to the applicable existing system rate for

the project service and requiring pipelines to use the

higher of the two as the recourse rate for project

service. Given the lack of interdependence between

the Dalton Expansion Project and the Leidy Southeast

Project, there is no basis for basing our subsidization

determination on a comparison, instead, of the rates of

the two expansion projects, as suggested by the State

Commissions.

5. Reporting Incremental Costs

40. Section 154.309 of the Commission’s regulations43

includes bookkeeping and accounting requirements

applicable to all expansions for which incremental

rates are approved to ensure that costs are properly

allocated between pipelines’ existing shippers and

incremental expansion shippers. Therefore, Transco

must keep separate books and accounting of costs and

revenues attributable to Dalton Lateral capacity and

incremental services using that capacity as required

by section 154.309. The books should be maintained

with applicable cross-references. This information

must be in sufficient detail so that the data can be

identified in Statements G, I, and J in any future NGA

section 4 or 5 rate case, and the information must be

provided consistent with Order No. 710.44

18 C.F.R. § 154.309 (2015).

Revisions to Forms, Statements, and Reporting Requirements

for Natural Gas Pipelines, Order No. 710, FERC Stats. & Regs.

¶ 31,267, at P 23 (2008).

30a

6. Lease Agreement

41. The Dalton Lateral will be jointly owned and

jointly funded by Transco and Dogwood, with each

party holding a 50 percent undivided joint ownership

interest. Dogwood will hold its 50 percent ownership

interest as a “passive owner” of the Lateral. On the inservice date of the project, Dogwood will lease its 50

percent ownership interest to Transco for a primary

term of 25 years. Transco asserts that during the lease

term it will have full possessory and operational rights

to the lateral and will have 100 percent of the capacity

rights on the lateral.

42. The Construction and Ownership Agreement

provides that Dogwood and Transco will jointly fund

the cost to construct the Dalton Lateral facilities in

proportion to their respective ownership interests.

Because Dogwood will be a passive owner, Transco

asserts that the Commission should find that Dogwood

does not require a certificate in connection with the

project. Accordingly, Transco requests that the certificate authority requested herein be granted solely to

Transco and pertain to 100 percent of the Dalton

Lateral facilities.

43. Transco asserts that it will utilize the capacity

rights under the lease, in conjunction with the

capacity to be created by the other project facilities, to

provide transportation services under its Tariff.

Transco further asserts that during the proposed

lease, all operating and maintenance expenses will be

Transco’s responsibility. Transco states that the Lease

Agreement includes a mechanism for Transco and

Dogwood to share maintenance capital expenditures

incurred by Transco to repair or replace the Dalton

Lateral facilities.

31a

44. The Lease Agreement provides for a primary

term of 25 years and may be extended, at Transco’s

option, for two successive five-year terms. Subject to

Transco’s right to extend the term of the Lease

Agreement, the Lease Agreement will continue in

effect for successive one-year extensions until prior

written notice to terminate is provided by Transco to

Dogwood. Transco asserts that at the termination of

the Lease Agreement, possessory and operational

rights to the leased facilities will revert to Dogwood,

subject to the receipt of the necessary authorizations

from the Commission.

45. The Lease Agreement provides that Transco

will pay to Dogwood a fixed monthly payment of

$2,140,916.70 for the 25-year primary term. The

monthly lease charge during each term extension will

be determined in accordance with a formula detailed

in Exhibit A of the Lease Agreement, reflecting an

adjusted annual cost of service for the Dalton Lateral

and a monthly unsubscribed capacity sharing factor,

if any. In addition, Transco will pay Dogwood a

maintenance capital surcharge in the form of a

monthly cost of service payment based on the amount

of maintenance capital expenditures, if any, reimbursed by Dogwood to Transco. Transco asserts that

its annual lease payments to Dogwood under the

Lease Agreement are less than the equivalent cost of

service that would apply if Transco directly owned 100

percent of the Dalton Lateral facilities (i.e., if Transco

constructed Dogwood’s 50 percent ownership share of

the Dalton Lateral instead of leasing Dogwood’s 50

percent ownership share).

46. Consistent with Commission regulations, Transco

proposes to record the lease as a capital lease in

Account 101.1, Property under Capital Leases, and the

32a

related obligation in Account 243, Obligations under

Capital Leases – Current, and Account 227, Obligations under Capital Leases – Noncurrent. Transco

contends that the lease qualifies as a capital lease

because the present value at the beginning of the lease

term of the minimum lease payments exceeds 90

percent of the fair value of the leased property to the

lessor at the inception of the lease. Transco states that

the costs and revenues associated with the project’s

leased facilities will be accounted for separately and

segregated from its other system costs.

47. Historically, the Commission views lease arrangements differently from transportation services under

rate contracts. The Commission views a lease of

interstate pipeline capacity as an acquisition of a

property interest that the lessee acquires in the

capacity of the lessor’s pipeline.45 To enter into a lease

agreement, the lessee generally is required to be a

natural gas company under the NGA and requires

section 7(c) certificate authorization to acquire the

capacity. Once acquired, the lessee in essence owns

that capacity and the capacity is subject to the lessee’s

tariff. The leased capacity is allocated for use by the

lessee’s customers. The lessor, while it may remain the

operator of the pipeline system, no longer has any

rights to use the leased capacity.46

48. The Commission’s practice has been to approve

a lease if it finds that: (1) there are benefits from using

a lease arrangement; (2) the lease payments are less

than, or equal to, the lessor’s firm transportation rates

Texas Eastern Transmission Corp., 94 FERC ¶ 61,139, at

61,530 (2001).

Texas Gas Transmission, LLC, 113 FERC ¶ 61,185, at P 10

(2005).

33a

for comparable service over the terms of the lease on a

net present value basis; and (3) the lease arrangement

does not adversely affect existing customers.47 We find

that the proposed lease agreement between Transco

and Dogwood satisfies these requirements.48

49. The Commission has found that capacity leases

in general have several potential benefits. Leases

can promote efficient use of existing facilities, avoid

construction of duplicative facilities, reduce the risk of

overbuilding, reduce costs, and minimize environmental impacts.49 In addition, leases can result in

administrative efficiencies for shippers.50

50. The annual amount Transco would pay Dogwood

under the lease is less than what it would cost if

Transco constructed and owned the facilities being

leased from Dogwood; thus, shippers will benefit from

the lease arrangement. During the 25 year primary

term of the Lease Agreement, Transco will pay

Midcontinent Express Pipeline LLC, 124 FERC ¶ 61,089

(2008), order on reh’g, 127 FERC ¶ 61,164 (2009), order on

remand, 134 FERC ¶ 61,155 (2011); Colorado Interstate Gas Co.,

122 FERC ¶ 61,256, at P 30 (2008); Gulf South Pipeline Co., L.P.,

119 FERC ¶ 61,281, at P 37 (2007).

The second criterion, that “the lease payments [be] less than,

or equal to, the lessor’s firm transportation rates for comparable

service of the terms of the lease on a net present value basis,” is

not applicable to the circumstances here, as Dogwood does not

provide transportation services and thus, has no firm transportation rates to which the lease payments may be compared.

See, e.g., Dominion Transmission, Inc., 104 FERC ¶ 61,267,

at P 21 (2003) (Dominion); Texas Gas Transmission, LLC, 113

FERC ¶ 61,185 at P 9; Islander East Pipeline Co., L.L.C., 100

FERC ¶ 61,276, at P 70 (2002).

Wyoming Interstate Co., Ltd., 84 FERC ¶ 61,007, at 61,027

(1998), reh’g denied, 87 FERC ¶ 61,011 (1999).

34a

Dogwood a fixed lease payment of $2,140,916.70 per

month for Dogwood’s ownership interest in the Dalton

Lateral. The annualized amount of such lease charge

is $25,691,000,51 which is then compared to the estimated annual cost of service of $46,445,747, assuming

Transco constructed and owned Dogwood’s share of

the Dalton Lateral.52 Since the annual amount to be

paid under the lease is less than the comparable cost

of service if Transco had constructed the facilities,

approval of this lease agreement will reduce Transco’s

costs associated with the project and thus the amount

shippers will pay under the recourse rate by an

estimated $20,754,747 per year.53

51. The State Commissions argue that Transco has

not demonstrated that its annual lease payments will

be less than the equivalent cost of service that would

apply if Transco directly owned 100 percent of the

facilities. The State Commissions assert that Transco’s

analysis of its annual lease payments is deficient,

because while the project lease has a 25-year primary

term, Exhibit N only analyzes one year of the lease.

Therefore, Transco’s analysis does not take into account

the impact of depreciation of the leased facilities on the

cost of service. As the leased facilities are depreciated

over time, the cost of service should decrease due to

the decrease in rate base. The State Commissions

contend that by limiting its analysis to one year,

Transco has failed to show that the lease payments

See Exhibit N, Line 14. The annualized amount of such lease

charge was calculated as follows: $2,140,916.70 times 12 equals

approximately $25,691,000.

See Exhibit N, Line 13 reflecting an estimated incremental

total cost of service to construct Dogwood’s ownership share of the

Dalton Lateral.

See Exhibit N, Line 15.

35a

over the life of the lease will be less than the equivalent cost of service that would apply if Transco directly

owned the facilities.

52. Transco states that it has included in its certificate application an analysis that includes a comparison

of the annual lease charges to an incremental annual

cost of service that would apply if Transco constructed

and owned 100 percent of the project facilities. Transco

states that its analysis used the first year of the lease

arrangement consistent with section 157.14(a)(18) of

the Commission’s regulations, which Transco states

requires Transco to calculate its initial recourse rates

for the project using a cost of service for the first

calendar year of operation after the proposed facilities

are placed in service. Thus, Transco argues that when

comparing Transco’s annual lease payments under the

lease arrangement to the estimated annual cost of

service assuming Transco constructed and owned

Dogwood’s share of the corresponding project facilities,

Transco appropriately used a first-year cost of service

analysis.

53. Transco’s analysis using the first year of the lease

arrangement is consistent with section 157.14(a)(18)

of the Commission’s regulations,54 and our approval

of the lease agreement is consistent with previous

Commission orders in which the Commission approved

the leasing of new capacity being constructed as part

Section 157.14(a)(18)(c)(ii)(a) of the Commission’s regulations provides in relevant part that “[w]hen new rates . . . are

proposed . . . [a statement explaining the basis used in arriving

at the proposed rate] shall be accompanied by supporting data

showing . . . system cost of service for the first calendar year of

operation after the proposed facilities are placed in service.”

36a

of a project based on the costs of that capacity.55 With

the lease agreement in place, Transco’s recourse rates

are lower than if Transco had constructed the capacity

itself, because Transco’s cost of service is lower under

the lease. The State Commissions are correct that,

assuming Transco constructed and owned 100 percent

of the facilities, its cost of service should decrease over

time. But, as stated above, rates are based on a first

year cost of service, and the pipeline is under no

obligation to reduce those rates over time. Therefore,

the lease arrangement provides lower rates and a

benefit to shippers.

54. In addition, we find that the lease arrangement

will not adversely affect Transco’s existing customers.

Transco proposes an incremental recourse rate designed

to recover the cost of service attributable to the project

facilities, including the payments under the Lease

Agreement. Therefore, existing shippers will not

subsidize the lease arrangement. In addition, Transco

has agreed to separately account for the costs and

revenues associated with the leased facilities and to

segregate those costs and revenues from its other

system costs during the term of the Lease Agreement.

Accordingly, the lease arrangement will not result in

adverse effects to Transco’s existing customers or on

any other pipelines or its customers.

55. The State Commissions are concerned that at

the termination of the lease agreement, possessory

and operational rights to the leased facilities will

revert to Dogwood, arguing that the use of the lease

ownership structure should not be allowed to evade or

See, e.g., Constitution Pipeline Co., 149 FERC ¶ 61,199

(2014); Tennessee Gas Pipeline Co., L.L.C. and National Fuel Gas

Supply Corp., 150 FERC ¶ 61,160 (2015).

37a

weaken the certificate holder’s obligations regarding

continuity of service. Specifically, the State Commissions assert that Transco has not fully fleshed out

the impact of its request that Dogwood, the co-owner

of the leased capacity, be exempt from any certificate

obligations with regard to the leased facilities. The

State Commissions recognize that the reversion at the

end of the term of the lease is subject to the receipt of

the necessary authorization from the Commission;

however, despite that qualification they are concerned

that approval of the lease, including the provision

regarding what occurs at the termination of the lease,

should not prejudge any issues regarding continuity of

service, or any other issue, at the end of the lease.56

The State Commissions assert that the Commission’s

long-standing policy is that when examining proposals

to abandon service, it weighs all relevant factors,

but considers “continuity and stability of existing

services . . . the primary considerations in assessing

whether the public convenience and necessity permit

abandonment.” Accordingly, the State Commissions

request that, in the event the Commission approves

the lease, it should clarify that nothing therein prejudges any issues as to the status of the leased

facilities, or the service provided on those facilities, at

the end of the lease.

56. Transco asserts that it is not requesting pregranted abandonment authority at the end of the

lease term. Transco further asserts that while the

passive owner lessor under the lease arrangement is

not required to apply for certificate authority, any

certificate authority granted will attach to 100 percent

State Commission’s Protest at 17 (citing Northern Natural

Gas Co., 142 FERC ¶ 61,120, at PP 10-11 (2013) and El Paso

Natural Gas Co., 136 FERC ¶ 61,180, at P 22 (2011)).

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of the project’s facilities and not just to Transco’s

ownership interest. Transco states that if at the end of

the lease the lessor desires to use the facilities for a

purpose other than that authorized by the certificate,

then Transco and the lessor will be required to obtain

the necessary abandonment authority under NGA

section 7(b) and interested parties will have ample

opportunity to participate in the section 7(b) proceeding for such abandonment.

57. The Commission clarifies that upon termination

of the lease at the end of its term or otherwise, Transco

must continue to provide jurisdictional service on the

Dalton Lateral until it requests and is authorized to

abandon the capacity under NGA section 7(b). Similarly,

if Transco files for authorization to abandon the leased

capacity, Dogwood or any other entity seeking to use

the capacity for jurisdictional service will need to file

for and receive the requisite certification authorizations under NGA section 7(c).

C. Environment

58. On April 25, 2014, the Commission staff began

its environmental review of the Dalton Expansion

Project by granting Transco’s request to use the prefiling process and assigning Docket No. PF14-10-000.57

Natural Resources Group, LLC (NRG) was selected at that

time as third-party contractor to assist Commission staff in the

development of the environmental assessment for the Dalton

Expansion Project. In September 2014, Environmental Resources

Group (ERM) acquired NRG. Subsequently, ERM notified

Commission staff of a possible conflict of interest, as ERM had

previously been engaged by Transco to provide air permitting

support and air dispersion analyses for inclusion in Transco’s

Dalton Expansion Project application; ERM included updated

Organizational Conflict of Interest forms with its notification. As

mitigation for the potential conflict, ERM proposed to establish

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As part of the pre-filing review, staff participated in

open houses sponsored by Transco in Newnan,

Carrollton, Dallas, Cartersville, Calhoun, and Dalton,

Georgia between June 9 and September 25, 2014, to

explain our environmental review process to interested stakeholders.

59. On October 21, 2014, the Commission issued

a Notice of Intent to Prepare an Environmental

Assessment for the Proposed Dalton Expansion Project,

Request for Comments on Environmental Issues, and

Notice of Public Scoping Meetings (NOI). The NOI

was published in the Federal Register58 and mailed

to interested parties including federal, state, and

local officials; elected officials; agency representatives;

environmental and public interest groups; Native

American tribes; local libraries and newspapers; and

affected property owners. FERC environmental staff

conducted three scoping meetings on November 3, 4,

and 5, 2014, in Dalton, Carrollton, and Cartersville,

Georgia to receive verbal scoping comments on the

an internal corporate firewall to isolate NRG and ERM project

and client teams for the duration of the respective third-party

contractor engagements. This mitigation was found to be acceptable. Though wholly-owned by ERM, NRG operated as a separate

entity until after its work for the Commission on the Dalton

Expansion Project was completed. Further, while NRG did review

the analyses done by ERM for Transco, the air dispersion analyses were also independently reviewed by Commission staff and

the conclusions on this modeling presented in the environmental

assessment are those of staff. Moreover, the air permitting

support provided by ERM was also independently reviewed by

the Georgia Department of Natural Resources - Environmental

Protection Division, which issued air quality permits on for

Compressor Station 116 and the Looper Bridge Road Meter

Station on March 11, 2015 and July 10, 2015, respectively.

79 Fed. Reg. 64186 (October 28, 2014).

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project. On November 14, 2014, the Commission

issued a Supplemental Notice of Intent to Prepare an

Environmental Assessment for the Planned Dalton

Expansion Project and Request for Comments on

Environmental Issues. This notice was also published

in the Federal Register59 and was mailed to over 1,100

interested parties and property owners affected by

the project facilities, notifying them that the scoping

period was extended through December 20, 2014.

60. As a result of concerns raised during the prefiling process by the Georgia Department of Natural

Resources (GADNR), the U.S. Fish and Wildlife

Service (FWS), and the Nature Conservancy, Transco

revised its planned route to avoid and minimize

potential environmental impacts on the biologically

sensitive Raccoon Creek Watershed. Accordingly, on

February 13, 2015, the Commission issued a second

Supplemental Notice of Intent to Prepare an Environmental Assessment for the Planned Dalton Expansion

Project and Request for Comments on Environmental

Issues. This notice was published in the Federal

Register60 and was mailed to over 1,270 interested

parties, including landowners that could be affected by

the route variation. Transco held a public open house

on February 24, 2015, in Dallas, Georgia to introduce

the project to landowners potentially affected by

the newly-developed route. Our environmental staff

held a fourth scoping meeting in Dallas, Georgia on

March 4, 2015, to receive verbal scoping comments

from stakeholders about the adjusted route. Eighteen

people spoke at the meeting. This newly-developed

route, referred to as the Raccoon Creek Alternative,

79 Fed. Reg. 69455 (Nov. 21, 2014).

80 Fed. Reg. 9710 (Feb. 24, 2015).

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was subsequently incorporated into the application for

the project on July 15, 2015.

61. In addition, as noted above, Bartow indicated

concern in its motion to intervene that the proposed

location of the Dalton Lateral would interfere with its

ability to expand two of its elementary schools on land

that it specifically acquired for that purpose. In a

response to those comments filed on October 21, 2015,

Transco stated it had incorporated Route Variation

AK as part of the Dalton Lateral – Segment 3, moving

the pipeline to a location slightly over 1000 feet from

the Taylorsville Elementary School, such that the route

no longer bisects the school property. The modified

route was reflected in Transco’s July 15, 2015 filing

and reviewed in the EA. Regarding the location of the

pipeline in the vicinity of the second school, Kingston

Elementary School, the pipeline follows an existing

overhead powerline, paralleling a corridor located

about 1,500 feet west of the school.

62. To satisfy the requirements of the National

Environmental Policy Act of 1969 (NEPA), our

staff prepared an environmental assessment (EA) for

Transco’s proposal. The analysis in the EA addresses

geology, soils, water resources, wetlands, vegetation,

fisheries, wildlife, threatened and endangered species,

land use, recreation, visual resources, cultural resources,

air quality, noise, safety, socioeconomics, cumulative

impacts, and alternatives. The EA addressed all substantive comments raised during the scoping period.

63. The EA was issued for a 30-day comment period

and placed into the public record on March 31, 2016.

The Commission received several comment letters

on the EA from individual stakeholders, the U.S.

Environmental Protection Agency (EPA), and the

Coosa River Basin Initiative (CRBI) regarding the

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impacts on the Etowah River, construction techniques,

potential impacts on water supply, effects of blasting,

cultural resources, cumulative effects, erosion and

production and end-user emissions.

1. April 2016 Modifications

64. On April 13, 2016, Transco filed 27 proposed

modifications to its project and on May 19 and 25,

2016, it filed additional information pertaining to

these modifications. Transco’s proposed modifications

would affect a total of 43 landowners, two of whom

were not previously affected by the project. Since

these proposals were made after the issuance of the

EA, while we will address them in this order, we will

consider them under the criteria established in

Environmental Condition 5. Environmental Condition

5 contemplates that there might be changes, such as

route realignments, facility relocations, new staging

areas, or access roads, identified after a project has

been certificated. Requests for such modifications

must include, among other information, documentation of affected-landowner approval and information

regarding potentially affected cultural resources,

endangered species, and environmentally sensitive

areas. As detailed below and consistent with the

criteria of Environmental Condition 5, we will only

grant approval for the modifications for which Transco

has both obtained landowner agreements and completed environmental surveys. For the remaining

proposed modifications, we will allow Transco to

present the required additional information and/or

justifications for the changes as required by Environmental Condition 5 of this order.

65. While Transco’s proposed modifications would

increase the pipeline length by 0.2 mile and total land

disturbance by 5.3 acres, the modifications would

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decrease the amount of forested wetlands impacted by

0.9 acre and eliminate four waterbody crossings.

Based on its May 19, 2016 filing, Transco has agreements with 25 of the 43 landowners impacted by the

modifications (covering 11 of the 27 modifications).

Transco continues to negotiate with the other 18

landowners. Transco has conducted environmental

surveys along 20 of the 27 proposed modifications. We

have reviewed the available survey reports for the

modifications and determined that the modifications

approved herein will not significantly increase impacts

on sensitive resources.

66. Transco proposed relocation of eight of its

mainline valves (MLV). Transco has completed environmental surveys and obtained landowner agreements

for the following six modifications: relocation of MLV

3 (from MP 34.5 to MP 34.3), MLV 6 (from MP 67.8 to

MP 64.2), and MLV 7 (from MP 77.9 to MP 78.2);

shifting MLV 8 at MP 85.3 (no change in MP), and

MLV 10 at MP 98.7 (no change in MP); and adding a

new MLV at MP 71.8. Having reviewed the submitted

information, we approve these modifications.

67. Transco has not completed environmental surveys

and has not obtained landowner agreements for the

property affected by the relocation of MLV 1 at MP

20.4 (no change in MP). Also, Transco has not obtained

landowner agreement for the relocation of MLV 9

(from MP 92.2 to MP 92.3). Accordingly, we will not

approve these modifications at this time.

68. Transco has completed environmental surveys

and obtained landowner agreements for two modifications along the Dalton Lateral: the addition of extra

workspace on the north and south sides of a railroad

crossing near MP 58.2 and a reroute of the Dalton

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Lateral between MPs 71.2 and 71.4 to avoid impacts

on Green Pond. We approve these modifications.

69. Transco has not completed environmental

surveys and/or obtained landowner agreement for the

following eight proposed modifications to the Dalton

Lateral: (1) a reroute between MPs 35.9 and 36.4 to

the west based on a landowner request; (2) shifting

the crossing of Highway 278 to the west between MPs

40.4 and 40.8 and the addition of two access roads;

(3) addition of a cathodic protection site at MP 51.0;

(4) reroute to the east between MPs 54.5 and 55.4 to

avoid crossing GADNR-owned lands and addition of a

new temporary access road; (5) reroute of an access

road near MP 56.5; (6) addition of extra workspace at

the Highway 278 crossing; (7) reroute and reduction of

the bore length at the Interstate 75 crossing between

MPs 76.6 and 77.9; and (8) reroute between MPs 95.7

and 96.9 to avoid multiple crossings of Polecat Creek.

We do not approve these modifications.

70. Transco also proposes to: (1) added a new access

road from the existing Compressor Station 115 to the

Dalton Lateral right-of-way; (2) relocate the Beasley

Road Meter Station (now called the Lucas Road Meter

Station) and add a new tap site and pipeline spur from

the Dalton Lateral at MP 53.2 to the new meter station

site; and (3) modify the portage path, which will be

used to move boats and kayaks around the construction area, on the southern side of the Etowah River.

Transco has not completed the environmental surveys

of the first of these modifications and has not obtained

landowner agreements for all the properties affected

by the second and third of these modifications.

Therefore, we do not approve these modifications.

71. Transco proposes five modifications that would

include locating workspace within streams. Because

45a

each of these changes will require modifications to

the project’s Wetland and Waterbody Construction

and Mitigation Procedures (Transco’s Procedures;

Appendix E of the EA), we will require additional

information to evaluate the feasibility of an alternative workspace layout or if additional protection

measures can be used to adequately protect the

streams. Accordingly, we do not approve these modifications at this time.

72. Finally, Transco proposes to reroute a portion of

the Dalton Lateral between MPs 30.3 and 30.4 to the

west to avoid impacts on a cemetery and to maintain

a 30-foot-wide no-disturbance buffer, as requested by

the Georgia State Historic Preservation Office. Transco

has neither completed the environmental surveys nor

obtained landowner agreements for all the properties

affected by this proposed reroute. Therefore, we will

not approve this modification. Further, the workspace

for this reroute would be located approximately 10 feet

from a house that was previously 400 feet from the

workspace. Additional information is needed for us to

evaluate Transco’s request and assess the feasibility of

an alternative route or crossing method to avoid

impacts on that residence.

73. To summarize, we approve incorporation of

eight of Transco’s requested modifications, as described

above, into the route authorized with this order. The

other 19 modifications are not approved. Transco may

present the required additional information and/or

justifications for these changes with its Implementation Plan and in accordance with Environmental

Condition 5 of this order. This condition requires

Transco to demonstrate compliance with Section 106

of the National Historic Preservation Act and Section

46a

7 of the Endangered Species Act prior to receiving

approval of any of the requested modifications.

2. Comments from the U.S. Environmental

Protection Agency

74. In its May 2, 2016 comment letter, the EPA

provided several recommendations and requested that

the Commission issue a supplemental EA to address

deficiencies identified in staff’s EA and to include

additional analysis addressing the 27 route modifications proposed after the EA was issued. In response,

we address the various comments from EPA in this

order and conclude that a supplemental EA for the

Dalton Expansion Project is not warranted.

75. First, the EPA recommends we address the

project’s potential to cause acid rock drainage during

construction. Acid-producing rocks are known to

occur in Georgia, and typically include graphitic

schist, phyllite, slate, coal, and carbonaceous shales,

which often contain pyrite. Counties that are crossed

by the Project in Georgia where these rocks are known

to occur include Paulding, Bartow, and Gordon. Acidproducing rocks are generally recognizable in the field

with an overall color of black or very-dark gray. Pyrite

has a gold metallic appearance.

76. In response to the EPA’s recommendation,

Transco agrees to evaluate the potential presence of

acid-producing rock or acidic soil along the project

route through review of U.S. Geologic Survey geologic

maps, U.S. Department of Agriculture – Natural

Resources Conservation Service Soil Surveys, and the

Soil Survey Geographic database, and to conduct field

47a

testing. Transco states that it will file with the

Commission, prior to construction, the results of its

desktop analysis identifying areas with the potential

for acid-producing rock or acidic soils, and a detailed

mitigation plan that outlines the procedures for field

verification and the mitigation measures that will be

implemented during construction.

77. Transco will also include a discussion on acidproducing rock and acidic soils in the environmental

training that will be required for environmental

inspectors before construction begins to familiarize the

environmental inspectors with the specific conditions

and issues associated with acid-producing rock and

acidic soils. We conclude that Transco’s proposed

measures are sufficient to address the EPA concerns.

78. The EPA also recommends that we address

karst areas of concern identified through desktop review

(topographic maps, aerial photographs, and LiDAR) in

Bartow and Murray Counties, Georgia. Transco has

conducted geophysical investigations at eight locations to gather additional information about these

features.62 Based on anomalies that were identified

during the geophysical investigations, soil borings

were performed at two locations to further define the

features and to determine if mitigation measures may

be needed during construction. The results of the soil

borings indicated that the conditions at the investigated locations should support the proposed pipeline

construction without karst mitigation measures. Three

See Transco’s Response to our November 13, 2015 Environmental Data Request, stating it will file the test borings before

commencing construction.

See Transco’s Report of Geophysical Services Karst Evaluation filed on August 13, 2015 in this proceeding.

48a

additional areas have been identified for soil borings

once access is available prior to construction in order

to determine if karst mitigation measures will be

required. The pipeline was re-routed away from three

of the eight locations where anomalies were identified;

therefore soil borings were not performed at those

locations. Environmental Condition 12 requires that

Transco file a revised Karst Mitigation Plan prior to

construction that includes the results of geotechnical

borings to determine the nature and extent of the

anomalies detected during the electric resistivity

imaging investigations as well as site-specific mitigation measures (e.g., route adjustment) for any karst

features identified. With this additional study, the

Commission’s review of the results, and Environmental Condition 12, we find the EPA’s concerns are

adequately addressed.

79. The EPA recommends that we address potential

scouring, erosion of river banks, and associated sediment discharges that could impact habitat for federally listed mussels where waterbodies are crossed via

dry-ditch and/or wet open crossings. On May 12, 2016,

the FWS filed with the Commission its biological

opinion (BO) on the project’s potential impacts on

aquatic species (see Threatened and Endangered

Species discussion below).63 The FWS states that

federally listed freshwater mussels are not known to

occur in the Oostanaula, Coosawattee, and Conasauga

River tributaries that the pipeline will cross, with the

exception of Holly Creek, where mussel populations

occur well upstream of the proposed crossing location.

The FWS also states that direct impacts on listed

See FWS’s Biological Opinion detailing potential impacts of

Transco’s proposed Dalton Expansion Project on aquatic species,

filed on May 12, 2016 in this proceeding.

49a

mussels are not anticipated but that erosion and

excessive sediment transport from these tributaries

due to pipeline construction and right-of-way could

impact listed mussels and their designated critical

habitat. However, the BO states that as proposed, the

project is not likely to jeopardize the continued existence of federally listed freshwater mussels identified

as potentially occurring in the project area and is not

likely to destroy or adversely modify critical habitat.

Based on analysis in the EA and the findings of the

FWS’ BO, we conclude that additional scour analysis

as recommended by the EPA is not warranted.

80. The EPA requests that we assess the cumulative effects of collocating pipeline rights-of-way with

existing rights-of-way, and that we evaluate the impacts

on sensitive ecosystems crossed by the proposed route.

As discussed in section B.3.c of the EA, although the

project may contribute to forest fragmentation, collocation and construction in previously disturbed areas

will minimize the effects of forest fragmentation and

forest edge effect caused by construction of the pipeline.64 In addition, Transco has deviated from existing

rights-of-way in areas where expanding the existing

right-of-way would affect sensitive habitats (e.g.,

portions of the Raccoon Creek watershed, Green Pond,

and Drummond Swamp). Further, as noted in the EA,

the presence of similar habitat types within the vicinity

of the project area will help ensure that the project

does not result in population-level or significant

EA at 54, see also EA at 52-53 (noting that much of the

woodland in the project area has already been fragmented

by agricultural land, managed timber operations, and other

developments).

50a

measurable negative impacts on birds of conservation

concern or other migratory birds.65

81. The EPA identifies concerns related to the

transfer of hydrostatic test water between watersheds

and expresses concerns about water withdrawals. The

EPA asserts that the associated aquatic ecosystems

should be assessed, particularly for drought conditions, the hydrostatic-testing frequency needed for

operations/maintenance, and impacts on federally

listed mussel species.

82. Transco states in its May 17, 2016 response

that surface water used for project construction and

operations will be removed from and returned to the

same watershed (8-digit hydrologic unit code) and that

no hydrostatic testing will be performed during

operations/maintenance.66 As stated in section B.2.b of

the EA, Transco will be required to obtain authorization from the GADNR prior to any water withdrawals

and to comply with all conditions set by the GADNR.67

Further, Transco will implement the measures outlined

in its Procedures (subject to Commission review and

modification as necessary) to minimize impacts on

waterbodies during withdrawals including maintaining adequate flow rates to protect aquatic life, provide

for all waterbody uses, and provide for downstream

withdrawals of water by existing users.68 We conclude

that Transco’s measures address the concerns expressed

by the EPA.

EA at 54-55.

Transco’s May 17, 2016 Response to the EPA’s Comments on

the EA.

EA at 40.

Id.; see also Environmental Condition 14.

51a

83. The EPA recommends that the EA address the

depth of the pipeline to mitigate the potential effects

of severe flooding events such as a 500-year flood that

could compromise the pipeline due to flood-water

scouring of the stream bottom, and cites as an example

the weakening and rupture of the Enterprise Product

Pipeline that was buried to a depth of 20 feet beneath

the Missouri River bed.

84. The Missouri River is the longest river in the

United States and has a drainage area of more than

half a million square miles. There is no waterbody

crossed by the project that is comparable. Moreover,

most of the larger waterbodies crossed by the project

will be crossed using the horizontal direction drill (HDD)

method, resulting in the pipeline being installed more

than 30 feet below the streambed. Additionally, the

pipeline will be constructed in accordance with Transco’s

Procedures and be subject to post-construction monitoring to identify areas of exposure as discussed in

section A.7.e and Appendix E of the EA.

85. The EPA identifies concerns related to the crossing of three major waterbodies: an unnamed tributary

to Jones Branch, an unnamed tributary to Crane

Eater Creek, and Pole Cat Creek. Transco states in its

May 17, 2016 response that the unnamed tributary to

Jones Branch is a man-made intermittent pond that

will be crossed using dry crossing methods. The unnamed

tributary to Crane Eater Creek is an agricultural stock

pond that will be drained under permission of the

owner. Finally, the referenced crossing of Pole Cat

Creek is no longer part of the proposed project. As

outlined in its Procedures, Transco will file detailed,

site-specific construction plans and scaled drawings

identifying all areas to be disturbed by construction for

each major waterbody crossing for the review and

52a

written approval (and additional mitigation measures

if warranted) by the Director of the Office of Energy

Projects prior to construction.

86. The EPA questions the number of streams

described in the EA. To clarify, the EA states that the

project will cross 55 coldwater fishery streams; 41 of

which will be crossed using a dry crossing method and

one will be crossed using the HDD method. The

remaining coldwater fisheries streams are within the

proposed construction workspace but will not be

crossed by the pipeline. Based on Transco’s April 2016

Supplemental Filing, two additional coldwater fisheries streams will be crossed. Therefore, the current

project, as modified, will cross 57 coldwater fisheries,

43 of which will be crossed using a dry crossing

method, one will be crossed using the HDD method,

and 13 that are within the proposed construction

workspace but will not be crossed by the pipeline.

87. The EPA identifies concerns related to the

crossing of a conservation easement associated with

Snake Creek. This conservation easement was avoided

by a route variation that was adopted in July 2015 and

was considered in the EA.

88. The EPA identifies concerns related to the

future conversion of the proposed pipeline from

natural gas transportation to the transportation of

natural gas liquids or petroleum products. Transco

states that it does not have any plans to abandon or

convert the pipeline to natural gas liquids or

petroleum products. Prior to any abandonment of the

pipeline, Transco would be required to obtain an

approval from the Commission under section 7(b) of

the NGA.

53a

89. The EPA identifies concerns related to the

storage of tert‐butyl mercaptan, the odorant used to

assist in the detection of pipeline leaks. Transco

indicates that odorization facilities are not proposed

for any component of the project. The supplemental

odorization control proposed by Transco will analyze

the gas composition and mercaptan levels in the gas

stream and signal the existing odorization stations to

inject less mercaptan or to supplement up to the

established level. The net effect will be the same

amount of mercaptan by volume in the delivered gas

stream to the customer. Transco anticipates that the

usage of the existing odorization facilities will be

reduced.69

90. The EPA recommends that the Commission

provide an estimate of both the production emissions,

including production-related fugitive emissions, and

end-user GHG emissions associated with the proposed

action in a supplemental NEPA document. As identified by Transco, gas transported by the project will be

delivered to the Oglethorpe Power – Chattahoochee

Energy Facility and to Atlanta Gas Light. We have

determined that there is no pending construction

or air quality permit application pending for the

Oglethorpe Power – Chattahoochee Energy Facility.

The project would deliver approximately 208 million

cubic feet per day to the facility, which may be used for

either future expansion or to displace current natural

gas supply. Should the gas be used for expansion,

there would be an increase in greenhouse gas emissions (GHGs) as well as criteria pollutants. If the

natural gas is displacing an existing gas supply, there

would be no change in emissions. If the gas is used to

Transco’s May 17, 2016 Response to the EPA’s Comments on

the EA.

54a

displace another fuel, such as oil or coal, then GHGs

would most likely be reduced. Regardless, changes in

the air permit would require approval by the Georgia

Department of Environmental Protection.

91. The remaining 240 million cubic feet per day

would be delivered to the Atlanta Gas Light, a local

distribution company (LDC). The LDC could distribute

the gas to residential, commercial, or industrial customers. Each of these end use scenarios result in very

different lifecyle GHG or criteria pollutant emissions.

We do not believe the potential increase of emissions

associated with the production and combustion of

natural gas is causally related to our action in approving this project, nor are the potential environmental

effects reasonably foreseeable as contemplated by the

Council on Environmental Quality’s (CEQ) regulations. Moreover, as the Commission has previously

stated, there is no standard method for determining

fugitive methane emissions for pipelines and the level

of fugitive methane releases during the lifecycle of

natural gas are highly debated. Therefore, it is difficult

to accurately quantify fugitive emissions of methane.70

Further, the EA explains that there is no standard

methodology to determine how a project’s incremental

contribution to GHG emissions would result in physical effects on the environment, either locally or

globally.71 We concur.72 Even if we determined that a

lifecycle GHG analysis was warranted, uncertainties

regarding both the LDC end uses, as well as numerous

See Transcontinental Gas Pipe Line Co. LLC, 149 FERC ¶

61,258, at P 109 (2014).

EA at 122.

See, e.g., Sabine Pass Liquefaction Expansion, LLC, 151

FERC ¶ 61,012 at P 97, reh’g denied, 151 FERC ¶ 61,253 (2015).

55a

production/upstream variables (gas source, pipeline

lengths, processing facilities, etc.) would make the

analysis too speculative to permit any meaningful consideration. In addition, given that potential production

areas are far removed from the geographic scope of the

project, identifying emissions of criteria pollutants

from production/upstream is even more speculative.

Speculative estimates of the end use and production/

upstream GHG emissions would not meaningfully

inform the Commission’s decision. There are no

thresholds for significance, nor is there a meaningful

method to determine the local or regional incremental

impacts on ongoing climate change.

92. The EPA expressed concerns about impacts on

carbon sequestration. Currently there are no federal

or state regulations regarding carbon sequestration.

According to the EPA, carbon sequestration is the

process through which plant life removes carbon

dioxide from the atmosphere and stores it in biomass.

The project will affect approximately 796 acres of

forested land, with 400 acres allowed to revert to forest

over time. While there will be a long-term effect of

reduced carbon sequestration due to removal of trees

from the permanent right-of-way, areas of temporary

disturbance will be allowed to revert to pre-existing

conditions. The young vegetation of the restored temporary right-of-way will continue to perform the

carbon sequestration process. The carbon sequestration ability of the permanent right-of-way will be

reduced; however, we conclude that the project will not

significantly impact cumulative carbon sequestration

in the United States. We also do not believe that the

potential reduction of greenhouse gas sinks will

significantly exacerbate ongoing climate change.

56a

3. Etowah River Crossing

93. The Commission received multiple comments

regarding the proposed Etowah River Crossing, including comments from the EPA, the Coosa River Basin

Initiative (CRBI), Darrel Cagle, and Troy Harris.

94. The EPA recommends that the EA evaluate

blasting impacts on karst terrain, specifically the

effects of blasting through karst during the crossing of

the Etowah River, and recommends that we address

sensitive ecosystem impacts.

95. The only waterbody for which blasting is currently proposed is the Etowah River. As discussed in

section B.2.b of the EA, Transco conducted a geotechnical investigation of the Etowah River crossing.

Given the degree of karst found during Transco’s

geophysical investigation, trenching for an open-cut

crossing of the Etowah River will be through karst

bedrock, which is likely to be conducive to techniques

such as rock sawing and hammering. If conditions

encountered are as expected, then blasting will not be

necessary. However, if blasting becomes necessary,

Transco will follow the pre-blasting monitoring requirements and post-blasting mitigation measures

contained in its project blasting plan, which includes

the development of site-specific mitigation measures.

Moreover, Environmental Condition 12 requires that

Transco file – for review and approval by the Commission – a revised Karst Mitigation Plan prior to

construction that will include site-specific mitigation

measures for any karst features identified.

96. The EPA requests information regarding compensatory mitigation related to the Etowah River

crossing. Compensatory mitigation will be addressed

by the U.S. Army Corps of Engineers (COE) during

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the COE permitting process for the Etowah River

crossing.73

97. The CRBI questions whether the EA fully

evaluated alternative crossing methods and requests

that the Commission independently review the feasibility of an HDD crossing of the river. Additionally,

the EPA commented that the EA did not include a

detailed analysis of the impacts associated with the

proposed crossing and requests that turbidity modeling be used to determine impacts. Furthermore, the

CRBI and Troy Harris question the reliability of the

borings collected within the river and request the

results of electric resistivity imaging testing near the

river. Lastly, the CRBI, EPA, Darrel Cagle, and Troy

Harris express concern regarding blasting and trenching and the resulting turbidity impacts. Troy Harris

questions the efficacy of turbidity curtains used during

construction, impacts associated with the installation

of the curtains, and potential downstream impacts

including stream bank erosion and sedimentation

affecting a sensitive cultural resource site identified as

the Indian Fish Weir.

98. As discussed in the EA, the information provided in Transco’s application and supplemental

filings is adequate to support the conclusion that the

use of the HDD crossing method is not appropriate at

this location. Environmental Condition 13 requires

that Transco provide, prior to construction, quantitative modeling results of turbidity and sedimentation,

including the duration, extent, and magnitude of

elevated turbidity levels and sedimentation due to

trenching, backfilling, and blasting (should it be

See Transco’s May 17, 2016 Response to the EPA’s Comments on the EA.

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required). The condition also requires Transco to file

its final Etowah River Turbidity Control and Monitoring

Plan, which was developed in coordination with the

GADNR and was provided to the FWS and COE for

review. The analysis already included in the EA, as

supplemented by the environmental conditions, is

sufficient to assess the impacts.

99. The CRBI questions the appropriateness of the

use of COE Nationwide Permit 12. The COE will make

the final determination on which type of permit the

project requires.

100. The CRBI requests that the Commission consider an alternative crossing location of the Etowah

River that will avoid a wet trench crossing. As

indicated in the EA, based on available U.S. Geological

Survey data and the results of the field investigations,

similar geologic conditions are expected within reasonable proximity to the proposed Etowah River crossing

location.74 Consequently, the alternative route identified by the CRBI would likely encounter similar

geology as the proposed location, which would preclude the use of an HDD crossing method. In addition,

the CRBI’s alternative route is approximately 3 miles

longer than the proposed route, which would result in

additional terrestrial impacts.

101. The CRBI comments that the EA did not

consider impacts on recreational use of the Etowah

River. Impacts on recreational use of the Etowah River

are addressed in section B.5.a of the EA. Transco’s

Draft Aid to Navigation Plan includes a plan identify74

See EA at 24. Environmental Condition 12 requires that,

before commencing construction, Transco must file a revised

Karst Mitigation Plan that includes site-specific mitigation

measures for any karst features identified.

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ing portage locations to be used by recreational users

during construction and a detailed signage plan to

inform recreational users of access limitations and

portage locations.

4. Alternatives

102. The Commission received several comments on

the EA regarding alternatives to the proposed pipeline

route, including comments from 1460 Partnership;

Evans & Rhodes, LLC; and the First Baptist Church

of Atlanta. The 1460 Partnership, LLLP provided a

map identifying three specific alternatives that

avoided their property. Evans & Rhodes, LLC did not

identify a specific alternative route but referenced an

alternative route on an adjacent undeveloped property. Based on our review of available information, we

determined that these alternatives are similar in

length or longer and would cross the same sensitive

resources (e.g., forest land) as the corresponding

segment of the proposed route without conferring an

obvious environmental advantage over the proposed

route. Further, these alternatives would require moving the route onto other landowners. For these reasons,

we are not authorizing these alternative routes.

103. The First Baptist Church of Atlanta identified

an alternative that would follow the church property

line, which is located adjacent to an existing powerline

right-of-way. Based on a preliminary review of the

alternative route, it appears to be feasible and remains

on the church property. We agree in this case that colocating along the power line right-of-way at the edge

of the property is preferable to bisecting the property.

Therefore, Environmental Condition 24 requires Transco

to either modify the pipeline route as requested by the

First Baptist Church of Atlanta, provide additional

justification why the alternative route cannot be incor-

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porated, or document landowner concurrence with the

currently proposed route.

104. David Shumaker identifies an alternative

route that would follow the existing access road to

Compressor Station 115 then head east along the

northern edge of Mr. Shumaker’s property where it

would connect with the proposed pipeline route. Based

on a preliminary review of the alternative route, it

appears to be feasible without impacting additional

landowners. Environmental Condition 24 requires

Transco to either modify the pipeline route as discussed above, provide additional justification why the

alternative route cannot be incorporated, or document

landowner concurrence with the currently proposed

route.

5. Threatened and Endangered Species

105. The Commission received several comments

on the EA regarding federally and state-listed species,

including comments from the EPA and 1460 Partnership. Section B.4. of the EA determines that constructing and operating the project will result in no effect on

13 threatened and endangered species; may affect, but

is not likely to adversely affect five threatened and

endangered species; and will not contribute to the

listing of one candidate species.

106. On April 5, 2016, the FWS filed a letter with

the Commission stating that it did not concur with

some of our staff’s determinations, based largely on

the possibility of erosion and sedimentation within

affected watersheds. However, the EA does include

measures to avoid and minimize potential erosion,

turbidity, and sedimentation impacts, as well as effects

attributable to hydrostatic test water withdrawals.

Based on our past experience with natural gas pipeline

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construction, the EA concludes that these measures

provide adequate protection for all resources that are

directly affected and substantially limits the potential

for any indirect impacts. However, in deference to the

opinions of the FWS, we adopted the FWS determinations in a letter to the FWS dated April 28, 2016. On

May 2, 2016, the FWS concurred with our revised

determinations. With receipt of the FWS concurrence,

and the subsequent BO addressing terrestrial species

dated May 9, 2016, the Endangered Species Act

Consultation process is complete and, as a result, EA

recommendation no. 19 is not included as a condition

of this order.

107. In a letter filed on April 28, 2016, Troy Harris

identifies concerns about the project’s potential impacts on an active bald eagle nest along the Etowah

River at Hardin Bridge. Because the closest construction areas are about 1.5 miles from the nest, construction

or operation of the project is not likely to affect it.75

108. Concerns regarding state-listed species are

adequately addressed in section B.4.b of the EA, which

concludes that the project is expected to have no

impact on 54 of the 58 state-listed species that are not

also federally listed and will have temporary and

minor impacts on four species.

6. Water Resources

109. On May 2, 2016, the CRBI filed a letter

identifying several Clean Water Act section 303(d)listed impaired waterbodies crossed by the proposed

pipeline route that were not specifically discussed in

As indicated on page 54 of the EA, Table B.3c-2, our environmental staff completed consultation with the FWS for the bald

eagle as part of the Birds of Conservation Concern, which is a

subset of the Migratory Bird Treaty Act.

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the EA. Based on Transco’s proposed construction

techniques and the implementation of minimization

and mitigation measures as outlined in section B.2.b

and Appendix E of the EA, we do not anticipate any

impact on the impairment criteria for these waterbodies during construction or operation of the project.

7. Land Use

110. Evans & Rhodes, LLC questions the use of

Wahoo Overlook Trail as an access road, noting such

use could block access to residents along the road.

Transco states that it no longer proposes to use this

road.76 If Transco proposes to use this road, it must file

a written request for our environmental staff’s review

and approval.

8. Environmental Conclusions

111. Based on the analysis in the EA, as supplemented herein, we conclude that if constructed in

accordance with Transco’s application and supplement(s),

and in compliance with the environmental conditions

in the appendix to this order, our approval of this

proposal would not constitute a major federal action

significantly affecting the quality of the human

environment.

112. Any state or local permits issued with respect

to the jurisdictional facilities authorized herein must

be consistent with the conditions of this certificate. We

encourage cooperation between interstate pipelines

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

EA Environmental Condition 4.

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the construction or operation of facilities approved by

this Commission.77

IV. Conclusion

113. 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) A certificate of public convenience and necessity

is issued to Transco authorizing it to construct and

operate the Dalton Expansion Project, as described

and conditioned herein, and as more fully described in

the application.

(B) The certificate authority granted in Ordering

Paragraph (A) is conditioned on Transco’s:

(1) completion of construction of the proposed

facilities and making them available for service

within two years of the issuance of this order

pursuant to section 157.20(b) of the Commission’s

regulations;

(2) compliance with all applicable Commission

regulations under the NGA including, but not

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).

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limited to Parts 154, 157, and 284, and paragraphs

(a), (c), (e), and (f) of section 157.20 of the

Commission’s regulations;

(3) compliance with the environmental conditions

in Appendix C to this order; and

(4) execution, prior to commencement of construction, of a firm contracts for the volumes and service

terms equivalent to those in its precedent agreement.

is issued under section 7(c) of the NGA authorizing

Transco to lease capacity from Dogwood, as described

herein and in the application.

(D) Transco’s initial incremental reservation charge

under Rate Schedule FT as recalculated for the project

to reflect the removal of variable costs is approved, as

discussed above.

(E) Transco shall file actual tariff records with the

recalculated base reservation charge no earlier than

60 days and no later than 30 days, prior to the date the

project goes into service.

(F) As described in this order, not less than 30 days

and not more than 60 days prior to the commencement

of service using the authorized expansion capacity,

Transco must file an executed copy of any nonconforming service agreement associated with the

project as part of its tariff, disclosing and reflecting all

non-conforming language, and a tariff record identifying each such agreement as a non-conforming agreement

consistent with section 154.112 of the Commission’s

regulations.

(G) As described in the body of this order, Transco

must file any negotiated rate agreement or tariff record

setting forth the essential terms of the agreement

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associated with the project at least 30 days, but not

more than 60 days before the proposed effective date

of such rates.

(H) Transco shall keep separate books and accounting of costs attributable to the incremental services

using the expansion capacity created by the project, as

discussed herein.

(I) Transco 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 Transco. Transco shall file written

confirmation of such notification with the Secretary of

the Commission (Secretary) within 24 hours.

(J) The State Commissions’ protest and request for

partial consolidation and evidentiary hearing is denied.

(K) The late motions to intervene are granted.

By the Commission.

(SEAL)

Nathaniel J. Davis, Sr.,

Deputy Secretary.

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Appendix A

Timely Motions to Intervene

Alabama Gas Corporation

Atlanta Gas Light Company

Atmos Energy Marketing, LLC

Bartow County School System and

Bartow County Board of Education

City of Cartersville, Georgia

Conoco Phillips Company

Consolidated Edison Company of New York, Inc.

and Philadelphia Gas Works

Duke Energy Carolinas, LLC

Municipal Gas Authority of Georgia78 and

Transco Municipal Group79

The Gas Authority consists, inter alia, of the following

municipalities which are served directly by Transco: the Georgia

municipalities of Bowman, Buford, Commerce, Covington, Elberton,

Hartwell, Lawrenceville, Madison, Monroe, Royston, Social

Circle, Sugar Hill, Toccoa, Winder, and Tri-County Natural Gas

Company (consisting of Crawfordville, Greensboro and Union

Point); the East Central Alabama Gas District, Alabama; the

towns of Wadley and Rockford, Alabama; the Utilities Board of

the City of Roanoke, Alabama; Wedowee Water, Sewer & Gas

Board, Wedowee, Alabama; and the Maplesville Waterworks and

Gas Board, Maplesville, Alabama.

The members of TMG include the Cities of Alexander City

and Sylacauga, Alabama; the Commissions of Public Works of

Greenwood, Greer, and Laurens, South Carolina; the Cities of

Fountain Inn and Union, South Carolina; the Patriots Energy

Group (consisting of the Natural Gas Authorities of Chester,

Lancaster and York Counties, South Carolina); and the cities of

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National Grid Gas Delivery Companies

New Jersey Natural Gas Company

NJR Energy Services Company

North Carolina Utilities Commission and New York

State Public Service

Commission

Oglethorpe Power Corporation

Piedmont Natural Gas Company, Inc.

PSEG Energy Resources & Trade LLC

SCE & GPSC of North Carolina

UGI Distribution Company

Bessemer City, Greenville, Kings Mountain, Lexington, Monroe,

Rocky Mount, Shelby, and Wilson, North Carolina.

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Appendix B

Late Motions to Intervene

1460 Partnership, LLLP

Coosa River Basin Initiative

David L. Shumaker

Handy Land and Timber, LLC

Ivan Goldenberg and Christine Cali Snellgrove Glenn

Paul Corley

Scott & Judy Mullis, Donna Gordon, Aimee and Phillip

Hutzelman, Kathleen and Michael Rossi, Darlos and

William Biossat, and Cynthia Schiller Jackson

Southern Company Services, Inc.

Virginia Corley Casey, Douglas Van Corley, Edward

Daniel Corley, Wanda Corley Haight, and Mary Corley

White

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Appendix C

Environmental Conditions

As recommended in the environmental assessment

(EA) this authorization includes the following

conditions:

1. Transcontinental Gas Pipe Line Company, LLC

(Transco) shall follow the construction procedures and

mitigation measures described in its application,

supplemental filings (including responses to staff data

requests), and as identified in the EA, unless modified

by the Order. Transco 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 sitespecific 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 (Director of OEP)

before using that modification.

2. The Director of OEP has delegated authority to

take whatever steps are necessary to ensure the

protection of all environmental resources during construction and operation of the project. This authority

shall allow:

a. the modification of conditions of the Order; and

b. the design and implementation of any additional measures deemed necessary (including stopwork authority) to ensure continued compliance

with the intent of the environmental conditions as

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well as the avoidance or mitigation of adverse

environmental impact resulting from construction

and operation of the project.

3. Prior to any construction of the facilities, Transco

shall file an affirmative statement with the Secretary,

certified by a senior company official, that all company

personnel, environmental inspectors (EIs), 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 for the project.

4. The authorized facility locations shall be as

shown in the EA, as supplemented by filed alignment

sheets. As soon as they are available and before the

start of construction, Transco shall file with the Secretary

any revised detailed survey alignment maps/sheets for

the project 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.

Transco’s exercise of eminent domain authority

granted under NGA section 7(h) in any condemnation

proceedings related to the Order must be consistent

with these authorized facilities and locations. Transco’s

right of eminent domain granted under NGA section

7(h) does not authorize it to increase the size of its

natural gas facilities to accommodate future needs or

to acquire a right-of-way for a pipeline to transport a

commodity other than natural gas.

5. Transco shall file with the Secretary detailed

alignment maps/sheets and aerial photographs at a

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scale not smaller than 1:6,000 identifying all route

realignments or facility relocations, and staging areas,

pipe storage and ware yards, new access roads, and

other areas for the project that would 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 endangered species would

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 Transco’s 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:

(i) implementation of cultural resources mitigation measures;

(ii) implementation of endangered, threatened, or

special concern species mitigation measures;

(iii) recommendations by state regulatory authorities; and

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(iv) agreements with individual landowners that

affect other landowners or could affect sensitive

environmental areas.

6. Within 60 days of the acceptance of the

Certificate and before construction begins, Transco

shall file an Implementation Plan for the project for

review and written approval by the Director of OEP.

Transco must file revisions to the plan as schedules

change. The plan shall identify:

a. how Transco will implement the construction

procedures and mitigation measures described in its

application and supplements (including responses to

staff data requests), identified in the EA, and

required by the Order;

b. how Transco 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 Transco will ensure that sufficient personnel

are available to implement the environmental

mitigation;

d. 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 Transco will

give to all personnel involved with construction and

restoration (initial and refresher training as the

project progresses and personnel changes), with the

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opportunity for OEP staff to participate in the

training session;

f. the company personnel (if known) and specific

portion of Transco’s organization having responsibility for compliance;

g. the procedures (including use of contract penalties) Transco will follow if noncompliance occurs;

and

h. for each discrete facility, a Gantt 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.

7. Transco shall employ one or more EIs per

construction spread. The EIs shall be:

a. responsible for monitoring and ensuring compliance with all mitigation measures required by the

Order and other grants, permits, certificates, or