36672 Federal Register / Vol. 83, No. 146 / Monday, July 30, 2018 / Rules and Regulations 

DEPARTMENT OF ENERGY 

Federal Energy Regulatory 

Commission 

18 CFR Parts 154, 260, and 284 

[Docket Nos. RM18–11–000, RP18–415–000; 

Order No. 849] 

Interstate and Intrastate Natural Gas 

Pipelines; Rate Changes Relating to 

Federal Income Tax Rate; American 

Forest & Paper Association 

AGENCY: Federal Energy Regulatory 

Commission, Department of Energy. 

ACTION: Final rule. 

SUMMARY: The Commission is adopting 

procedures for determining which 

jurisdictional natural gas pipelines may 

be collecting unjust and unreasonable 

rates in light of the income tax 

reductions provided by the Tax Cuts 

and Jobs Act and the Commission’s 

revised policy and precedent 

concerning tax allowances to address 

the double recovery issue identified by 

United Airlines, Inc. v. FERC. These 

procedures also allow interstate natural 

gas pipelines to voluntarily reduce their 

rates. 

DATES: This rule is effective September 

13, 2018. 

FOR FURTHER INFORMATION CONTACT: 

Adam Eldean (Legal Information), Office 

of the General Counsel, 888 First 

Street NE, Washington, DC 20426, 

(202) 502–8047, Adam.Eldean@

ferc.gov 

Seong-Kook Berry (Technical 

Information), Office of Energy Market 

Regulation, 888 First Street NE, 

Washington, DC 20426, (202) 502– 

6544, Seong-Kook.Berry@ferc.gov 

SUPPLEMENTARY INFORMATION: 

Before Commissioners: Kevin J. 

McIntyre, Chairman; Cheryl A. 

LaFleur, Neil Chatterjee, Robert F. 

Powelson, and Richard Glick. 

Table of Contents 

Paragraph 

Nos. 

I. Introduction ............................................................................................................................................................................... 1 

II. Background ............................................................................................................................................................................... 5 

A. Tax Cuts and Jobs Act ...................................................................................................................................................... 5 

B. United Airlines Issuances ................................................................................................................................................. 6 

C. Overview of Natural Gas Rates ........................................................................................................................................ 10 

1. The Natural Gas Act .................................................................................................................................................. 10 

2. The Natural Gas Policy Act of 1978 ......................................................................................................................... 16 

D. Request for Commission Action ...................................................................................................................................... 19 

E. Notice of Proposed Rulemaking ....................................................................................................................................... 21 

F. Comments on Notice of Proposed Rulemaking ............................................................................................................... 23 

III. Overview of Final Rule .......................................................................................................................................................... 29 

IV. Discussion ............................................................................................................................................................................... 37 

A. Treatment of Pass-through Entities ................................................................................................................................. 37 

1. NOPR .......................................................................................................................................................................... 37 

2. Comments ................................................................................................................................................................... 39 

a. Challenges to the Commission’s response to United Airlines ......................................................................... 41 

b. Arguments Regarding the Implementation ....................................................................................................... 44 

3. Discussion .................................................................................................................................................................. 49 

a. Limited Section 4 Filings ................................................................................................................................... 51 

b. FERC Form No. 501–G and Addendum ............................................................................................................ 58 

c. Other Issues ......................................................................................................................................................... 62 

B. One-time Report ................................................................................................................................................................ 63 

1. Legal Authority .......................................................................................................................................................... 67 

a. Comments ............................................................................................................................................................ 67 

b. Discussion ........................................................................................................................................................... 69 

2. Burden of Proof .......................................................................................................................................................... 77 

a. Comments ............................................................................................................................................................ 77 

b. Discussion ........................................................................................................................................................... 78 

3. Docketing and Comments .......................................................................................................................................... 80 

a. Comments ............................................................................................................................................................ 81 

b. Discussion ........................................................................................................................................................... 84 

4. Rights of Intervenors .................................................................................................................................................. 93 

a. Comments ............................................................................................................................................................ 94 

b. Discussion ........................................................................................................................................................... 95 

5. Use of 10.55 Percent Indicative Return on Equity ................................................................................................... 100 

a. Comments ............................................................................................................................................................ 101 

b. Discussion ........................................................................................................................................................... 103 

6. Use of Stated Capital Structure ................................................................................................................................. 107 

a. Comments ............................................................................................................................................................ 109 

b. Discussion ........................................................................................................................................................... 111 

7. Accumulated Deferred Income Taxes ....................................................................................................................... 116 

a. Comments ............................................................................................................................................................ 120 

b. Discussion ........................................................................................................................................................... 128 

8. Who Must File ........................................................................................................................................................... 153 

a. Comments ............................................................................................................................................................ 154 

b. Discussion ........................................................................................................................................................... 158 

9. Miscellaneous Changes to FERC Form No. 501–G .................................................................................................. 166 

a. Comments and Discussion ................................................................................................................................. 166 

C. Additional Filing Options for Natural Gas Companies .................................................................................................. 190 

1. Limited NGA Section 4 Filing (Option 1) ................................................................................................................ 191 

a. NOPR ................................................................................................................................................................... 191 

b. Comments ............................................................................................................................................................ 193 

c. Discussion ........................................................................................................................................................... 198 


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Federal Register / Vol. 83, No. 146 / Monday, July 30, 2018 / Rules and Regulations 36673 

1An Act to provide for reconciliation pursuant to 

titles II and V of the concurrent resolution on the 

budget for fiscal year 2018, Public Law 115–97, 131 

Stat. 2054 (2017) (Tax Cuts and Jobs Act). 

2 Inquiry Regarding the Commission’s Policy for 

Recovery of Income Tax Costs, Revised Policy 

Statement, 83 FR 12,362 (Mar. 21, 2018), FERC Stats 

& Regs. ¶ 35,060 (2018), order on reh’g, 164 FERC 

¶ 61,030 (2018). 

3SFPP, L.P., Opinion No. 511–C, 162 FERC 

¶ 61,228, at P 9 (2018). 

4United Airlines, Inc. v. FERC, 827 F.3d 122 (D.C. 

Cir. 2016). For purposes of this order, the Revised 

Policy Statement, United Airlines, and Opinion No. 

511–C will collectively be referred to as ‘‘United 

Airlines Issuances.’’ 

5 Interstate and Intrastate Natural Gas Pipelines; 

Rate Changes Relating to Federal Income Tax Rate, 

83 FR 12,888 (Mar. 26, 2018), FERC Stats. & Regs. 

¶ 32,725 (2018) (NOPR). 

6 15 U.S.C. 717c (2012). 

7Throughout this order, as in prior Commission 

orders, we use the phrase ‘‘MLP pipeline.’’ For the 

purposes of this proceeding, MLP pipeline includes 

a pipeline, such as SFPP, L.P., that does not pay 

taxes itself and is a wholly-owned subsidiary of an 

MLP. See Opinion No. 511–C, 162 FERC ¶ 61,228 

at P 9. 

Paragraph 

Nos. 

2. General NGA Section 4 Filing or Prepackaged Uncontested Settlement (Option 2) ............................................. 206 

a. NOPR ................................................................................................................................................................... 206 

b. Comments ............................................................................................................................................................ 207 

c. Discussion ........................................................................................................................................................... 211 

3. Statement That No Adjustment in Rates Needed (Option 3) .................................................................................. 216 

a. NOPR ................................................................................................................................................................... 216 

b. Comments ............................................................................................................................................................ 218 

c. Discussion ........................................................................................................................................................... 222 

4. Take No Action (Option 4) ........................................................................................................................................ 226 

a. NOPR ................................................................................................................................................................... 226 

b. Comments ............................................................................................................................................................ 227 

c. Discussion ........................................................................................................................................................... 228 

D. Negotiated Rates ............................................................................................................................................................... 229 

1. Comments ................................................................................................................................................................... 231 

2. Discussion .................................................................................................................................................................. 245 

E. Miscellaneous Clarifications ............................................................................................................................................ 250 

F. Implementation Schedule for Informational Filings ...................................................................................................... 261 

1. NOPR .......................................................................................................................................................................... 261 

2. Comments ................................................................................................................................................................... 262 

3. Discussion .................................................................................................................................................................. 265 

G. NGPA section 311 and Hinshaw Pipelines ..................................................................................................................... 267 

1. NOPR .......................................................................................................................................................................... 267 

2. Comments ................................................................................................................................................................... 270 

3. Discussion .................................................................................................................................................................. 277 

H. Request for Commission Action ...................................................................................................................................... 285 

V. Regulatory Requirements ........................................................................................................................................................ 286 

A. Information Collection Statement ................................................................................................................................... 286 

B. Environmental Analysis ................................................................................................................................................... 293 

C. Regulatory Flexibility Act ................................................................................................................................................ 294 

D. Document Availability ..................................................................................................................................................... 297 

E. Effective Date and Congressional Notification ................................................................................................................ 300 

I. Introduction 

1. In this Final Rule, the Commission 

adopts procedures for determining 

which jurisdictional natural gas 

pipelines may be collecting unjust and 

unreasonable rates in light of (1) the 

income tax reductions provided by the 

Tax Cuts and Jobs Act 1 and (2) the 

Commission’s Revised Policy 

Statement 2 and Opinion No. 511–C3

concerning income tax allowances 

following the decision of the United 

States Court of Appeals for the District 

of Columbia Circuit (D.C. Circuit) in 

United Airlines.4 These procedures also 

allow interstate natural gas pipelines to 

voluntarily reduce their rates to reflect 

the income tax reductions and United 

Airlines Issuances. 

2. The procedures adopted in this 

Final Rule are generally the same as the 

Commission proposed in its March 15, 

2018 Notice of Proposed Rulemaking 

(NOPR or proposed rule) in this 

proceeding.5 The Commission is thus 

adopting, with clarifications, the 

proposed FERC Form No. 501–G 

informational filing for evaluating the 

impact of the Tax Cuts and Jobs Act and 

United Airlines Issuances on interstate 

natural gas pipelines’ revenue 

requirements. The Commission is also 

providing four options each interstate 

natural gas pipeline may choose from to 

address the changes to the pipeline’s 

revenue requirement as a result of the 

income tax reductions: (1) A limited 

Natural Gas Act (NGA) section 4 6 rate 

reduction filing, (2) a commitment to 

file a general section 4 rate case in the 

near future, (3) an explanation why no 

rate change is needed, and (4) no action 

(other than filing a report). 

3. However, as discussed further 

below, the Final Rule modifies the 

NOPR’s proposed treatment of master 

limited partnership (MLP) pipelines 7

and other pass-through entities in 

several respects. First, the Commission 

has modified the FERC Form No. 501– 

G so that, if a pipeline states that it is 

not a tax paying entity, the form will not 

only automatically enter a federal and 

state income tax of zero, but also 

eliminate Accumulated Deferred Income 

Taxes (ADIT) from the pipeline’s cost of 

service. Second, if an MLP pipeline 

chooses Option 1 (limited section 4 rate 

filing), this Final Rule permits the 

pipeline to reflect only the tax 

reductions in the Tax Cuts and Jobs Act. 

Although the Commission determined 

in the Revised Policy Statement that 

permitting MLP pipelines to include a 

tax allowance in their cost of service 

results in a double recovery of the MLP 

pipeline’s tax costs, this Final Rule does 

not require MLP pipelines to eliminate 

their tax allowances at this time in 

compliance with this rulemaking. Third, 

the Final Rule clarifies that a natural gas 

company organized as a pass-through 

entity all of whose income or losses are 

consolidated on the federal income tax 

return of its corporate parent is 

considered to be subject to the federal 

corporate income tax, and is thus 

eligible for a tax allowance. 

4. The Final Rule also makes certain 

changes to the proposed FERC Form No. 


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8See Tax Cuts and Jobs Act 13001, 131 Stat. at 

2096. 

9See id. 11011, 131 Stat. at 2063. 

10 Inquiry Regarding the Commission’s Policy for 

Recovery of Income Tax Costs, Notice of Inquiry, 

FERC Stats & Regs. ¶ 35,581 (2016). 

11Opinion No. 511–C, 162 FERC ¶ 61,228. 

12 Id. P 22. 

13 Id. P 21. 

14Revised Policy Statement, FERC Stats. & Regs. 

¶ 35,060. 

15Policy Statement on Income Tax Allowances, 

111 FERC ¶ 61,139 (2005). 

16Revised Policy Statement, FERC Stats. ¶ Regs. 

35,060 at P 3. 

17 18 CFR 284.10 (2017). 

18Most pipeline tariffs include tracking 

mechanisms for the recovery of fuel and lost and 

unaccounted for gas, but generally pipelines do not 

separately track any other cost. 

19 18 CFR 154.312 and 154.313. The pipeline 

must show the computation of its allowance for 

federal income taxes in Statement H–3. 

20See, e.g., Trunkline Gas Co., 142 FERC 

¶ 61,133, at P 24 n.28 (2013). 

21ANR Pipeline Co., 110 FERC ¶ 61,069, at P 18 

(2005). 

22 Midwestern Gas Transmission Co., 162 FERC 

¶ 61,219 (2018); Dominion Energy Overthrust 

Pipeline, LLC, 162 FERC ¶ 61,218 (2018); Natural 

501–G, including modifying the 

hypothetical capital structure to be used 

by pipelines who cannot use their own 

or their parent’s capital structure. In 

addition, the Final Rule provides a 

guarantee that the Commission will not 

initiate a NGA section 5 rate 

investigation for a three-year 

moratorium period of an interstate 

pipeline that makes a limited NGA 

section 4 rate reduction filing that 

reduces its ROE to 12 percent or less. 

II. Background 

A. Tax Cuts and Jobs Act 

5. On December 22, 2017, the 

President signed into law the Tax Cuts 

and Jobs Act. The Tax Cuts and Jobs 

Act, among other things, reduces the 

federal corporate income tax rate from 

35 percent to 21 percent, effective 

January 1, 2018. This means that, 

beginning January 1, 2018, companies 

subject to the Commission’s jurisdiction 

will compute income taxes owed to the 

Internal Revenue Service (IRS) based on 

a 21 percent tax rate. The tax rate 

reduction will result in less corporate 

income tax expense going forward.8

Further, with respect to income derived 

from pass-through entities, the Tax Cuts 

and Jobs Act generally reduced the 

income tax liability for individuals, and 

permitted up to a 20 percent deduction 

of pass-through income.9 The 

combination of these two changes for 

individuals holding units of passthrough entities means that the effective 

tax level applicable to individuals with 

pass-through derived income may be 

slightly less than the corporate income 

tax. 

B. United Airlines Issuances 

6. In United Airlines, the D.C. Circuit 

held that the Commission failed to 

demonstrate that allowing SFPP, L.P. 

(SFPP), an MLP pipeline, to recover 

both an income tax allowance and the 

discounted cash flow (DCF) 

methodology rate of return does not 

result in a double recovery of investors’ 

tax costs. Accordingly, the D.C. Circuit 

remanded the underlying rate 

proceeding to the Commission for 

further consideration. Although the D.C. 

Circuit’s decision directly addressed the 

rate case filed by SFPP, the United 

Airlines double-recovery analysis 

referred to partnerships generally. 

Recognizing the potentially industrywide ramifications, the Commission 

issued a Notice of Inquiry in Docket No. 

PL17–1–000, soliciting comments on 

how to resolve any double recovery 

resulting from the rate of return policies 

and the policy permitting an income tax 

allowance for partnership entities.10

7. Concurrently with the issuance of 

the NOPR in this proceeding, the 

Commission issued an Order on 

Remand in Opinion No. 511–C11 in 

response to United Airlines. Consistent 

with the United Airlines remand, 

Opinion No. 511–C concluded that 

granting SFPP an income tax allowance 

in addition to its return on equity (ROE) 

determined by the DCF methodology 

resulted in a double-recovery. The 

Commission explained: 

[MLP pipelines (such as SFPP)] and similar 

pass-through entities do not incur income 

taxes at the entity level. Instead, the partners 

are individually responsible for paying taxes 

on their allocated share of the partnership’s 

taxable income. 

The DCF methodology estimates the 

returns a regulated entity must provide to 

investors in order to attract capital. 

To attract capital, entities in the market 

must provide investors a pre-tax return, i.e., 

a return that covers investor-level taxes and 

leaves sufficient remaining income to earn 

investors’ required after-tax return. In other 

words, because investors must pay taxes from 

any earnings received from the partnership, 

the DCF return must be sufficient both to 

cover the investor’s tax costs and to provide 

the investor a sufficient after-tax ROE.12

8. Accordingly, the Commission 

ordered removal of the additional 

income tax allowance from SFPP’s cost 

of service. The Commission explained 

that such action (a) remedies the double 

recovery identified by the court in its 

United Airlines remand, (b) restores 

parity between SFPP (an MLP pipeline) 

and corporate investment forms, (c) is 

consistent with Congressional intent, 

and (d) provides SFPP with a sufficient 

return via the DCF ROE.13

9. Simultaneously, the Commission 

also issued the Revised Policy 

Statement 14 that superseded the 

Commission’s prior guidance in the 

2005 Income Tax Policy Statement 15

and established new guidance following 

United Airlines. Like Opinion No. 511– 

C, the Revised Policy Statement 

explained that a double recovery results 

from granting an MLP pipeline an 

income tax allowance and a DCF ROE, 

and accordingly provided guidance that 

the Commission will no longer permit 

MLP pipelines to recover an income tax 

allowance in their cost of service. The 

Revised Policy Statement also explained 

that although all partnerships seeking to 

recover an income tax allowance in a 

cost-of-service rate case will need to 

address the United Airlines doublerecovery concern, the Commission will 

address the application of United 

Airlines to these non-MLP partnership 

forms as those issues arise in 

subsequent proceedings.16 The 

Commission received requests for 

rehearing of Opinion No. 511–C and the 

Revised Policy Statement. 

C. Overview of Natural Gas Rates 

1. The Natural Gas Act 

10. As required by § 284.10 of the 

Commission’s regulations,17 interstate 

natural gas pipelines generally have 

stated rates for their services, which are 

approved in a rate proceeding under 

NGA sections 4 or 5 and remain in effect 

until changed in a subsequent NGA 

section 4 or 5 proceeding. The stated 

rates are designed to provide the 

pipeline the opportunity to recover all 

components of the pipeline’s cost of 

service, including the pipeline’s federal 

income taxes.18 When pipelines file 

under NGA section 4 to change their 

rates, the Commission requires the 

pipeline to provide detailed support for 

all the components of its cost of service, 

including federal income taxes.19

11. The Commission generally does 

not permit pipelines to change any 

single component of their cost of service 

outside of a general NGA section 4 rate 

case.20 A primary reason for this policy 

is that, while one component of the cost 

of service may have increased, others 

may have declined. In a general NGA 

section 4 rate case, all components of 

the cost of service may be considered 

and any decreases in an individual 

component can be offset against 

increases in other cost components.21

For the same reasons, the Commission 

reviews all of a pipeline’s costs and 

revenues when it investigates whether a 

pipeline’s existing rates are unjust and 

unreasonable under NGA section 5.22


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Gas Pipeline Co. of America LLC, 158 FERC 

¶ 61,044 (2017); Wyoming Interstate Co., L.L.C., 158 

FERC ¶ 61,040 (2017); Tuscarora Gas Transmission 

Co., 154 FERC ¶ 61,030 (2016); Iroquois Gas 

Transmission System, L.P., 154 FERC ¶ 61,028 

(2016); Empire Pipeline, Inc., 154 FERC ¶ 61,029 

(2016); Columbia Gulf Transmission, LLC, 154 

FERC ¶ 61,027 (2016); Wyoming Interstate Co., 

L.L.C., 141 FERC ¶ 61,117 (2012); Viking Gas 

Transmission Co., 141 FERC ¶ 61,118 (2012); Bear 

Creek Storage Co., L.L.C., 137 FERC ¶ 61,134 (2011); 

MIGC LLC, 137 FERC ¶ 61,135 (2011); ANR Storage 

Co., 137 FERC ¶ 61,136 (2011); Ozark Gas 

Transmission, L.L.C., 133 FERC ¶ 61,158 (2010); 

Kinder Morgan Interstate Gas Transmission LLC, 

133 FERC ¶ 61,157 (2010); Northern Natural Gas 

Co., 129 FERC ¶ 61,159 (2009); Great Lakes Gas 

Transmission Ltd. P’ship, 129 FERC ¶ 61,160 

(2009); Natural Gas Pipeline Co. of America LLC, 

129 FERC ¶ 61,158 (2009). 

23 18 CFR 385.602(g)(3). 

24See Natural Gas Pipeline Negotiated Rate 

Policies and Practices; Modification of Negotiated 

Rate Policy, 104 FERC ¶ 61,134 (2003), order on 

reh’g and clarification, 114 FERC ¶ 61,042, 

dismissing reh’g and denying clarification, 114 

FERC ¶ 61,304 (2006) (Negotiated Rate Policy 

Statement). 

25Northern Natural Gas Co., 105 FERC ¶ 61,299, 

at PP 15–16 (2003). 

26Alternatives to Traditional Cost of Service 

Ratemaking for Natural Gas Pipelines and 

Regulation of Negotiated Transportation Services of 

Natural Gas Pipelines, 74 FERC ¶ 61,076 (1996) 

(Negotiated Rate Policy Statement); see also Rate 

Regulation of Certain Natural Gas Storage 

Facilities, Order No. 678, FERC Stats. & Regs. 

¶ 31,220 (2006) (cross-referenced at 115 FERC 

¶ 61,343), reh’g denied, Order No. 678–A, 117 FERC 

¶ 61,190 (2006). 

27 15 U.S.C. 3371. 

28 15 U.S.C. 3371(a)(2)(B). 

29 15 U.S.C. 3371(c). 

30Section 1(c) of the NGA, 15 U.S.C. 717(c), 

exempts from the Commission’s NGA jurisdiction 

those pipelines which transport gas in interstate 

commerce if (1) they receive natural gas at or within 

the boundary of a state, (2) all the gas is consumed 

within that state, and (3) the pipeline is regulated 

by a state Commission. This is known as the 

Hinshaw exemption. 

31See 18 CFR 284.224. 

32 18 CFR 284.123. 

33 18 CFR 284.123(b). 

34Contract Reporting Requirements of Intrastate 

Natural Gas Companies, Order No. 735, FERC Stats. 

& Regs. ¶ 31,310, at P 92, order on reh’g, Order No. 

735–A, FERC Stats. & Regs. ¶ 31,318 (2010); see 

also Hattiesburg Industrial Gas Sales, L.L.C., 134 

FERC ¶ 61,236 (2011) (imposing a five-year rate 

review requirement on Hattiesburg Industrial Gas 

Sales, L.L.C.). 

12. NGA sections 4 and 5 proceedings 

are routinely resolved through 

settlement agreements between the 

pipeline and its customers. Most of the 

agreements are ‘‘black box’’ settlements 

that do not provide detailed cost-ofservice information. In addition, in lieu 

of submitting a general NGA section 4 

rate case, a pipeline may submit a prepackaged settlement to the Commission. 

When pipelines file pre-packaged 

settlements, they generally do not 

include detailed cost and revenue 

information in the filing. The 

Commission will approve an 

uncontested settlement offer upon 

finding that ‘‘the settlement appears to 

be fair and reasonable and in the public 

interest.’’ 23 Many rate case settlement 

agreements include moratorium 

provisions that limit the ability of the 

pipeline to file to revise its rates, or for 

the shippers to file an NGA section 5 

complaint, for a particular time period. 

In addition, many settlement 

agreements include ‘‘come-back 

provisions,’’ which require a pipeline to 

file an NGA section 4 filing no later than 

a particular date. 

13. The Commission has granted most 

interstate natural gas pipelines authority 

to negotiate rates with individual 

customers.24 Such rates are not bound 

by the maximum and minimum 

recourse rates in the pipeline’s tariff.25

In order to be granted negotiated rate 

authority, a pipeline must have a costbased recourse rate on file with the 

Commission, so a customer always has 

the option of entering into a contract at 

the cost-based recourse rate rather than 

a negotiated rate if it chooses. The 

pipeline must file each negotiated rate 

agreement with the Commission. In 

addition, pipelines are also permitted to 

selectively discount their rates. 

Although negotiated rates may be above 

the maximum recourse rate, discounted 

rates must remain below the maximum 

rate. The maximum recourse rate is the 

ceiling rate for all long-term capacity 

releases, including capacity releases to 

replacement shippers by firm customers 

with negotiated rates. 

14. Changes to a pipeline’s recourse 

rates occurring under NGA sections 4 

and 5 do not affect a customer’s 

negotiated rate, because that rate is 

negotiated as an alternative to the 

customer taking service under the 

recourse rate. However, a shipper 

receiving a discounted rate may 

experience a reduction as a result of the 

outcome of a rate proceeding if the 

recourse rate is reduced below the 

discounted rate. The prevalence of 

negotiated and discounted rates varies 

among pipelines, depending upon the 

competitive situation. 

15. The Commission also grants 

interstate natural gas pipelines marketbased rate authority when the pipeline 

can show it lacks market power for the 

specific services or when the applicant 

or the Commission can mitigate the 

market power with specific 

conditions.26 A pipeline that has been 

granted market-based rate authority will 

have an approved tariff on file with the 

Commission but will not have a 

Commission approved rate. Rather, all 

rates for services are negotiated by the 

pipeline and its customers. Currently, 

29 interstate natural gas pipelines have 

market-based rate authority for storage 

and interruptible hub services (such as 

wheeling and park and loan services), 

and one pipeline (Rendezvous Pipeline 

Company, LLC) has market-based rate 

authority for transportation services. 

2. The Natural Gas Policy Act of 1978 

16. Section 311 of the Natural Gas 

Policy Act of 1978 (NGPA) authorizes 

the Commission to allow intrastate 

pipelines to transport natural gas ‘‘on 

behalf of’’ interstate pipelines or local 

distribution companies served by 

interstate pipelines.27 NGPA section 

311(a)(2)(B) provides that the rates for 

interstate transportation provided by 

intrastate pipelines shall be ‘‘fair and 

equitable and may not exceed an 

amount which is reasonably comparable 

to the rates and charges which interstate 

pipelines would be permitted to charge 

for providing similar transportation 

service.’’ 28 In addition, NGPA section 

311(c) provides that any authorization 

by the Commission for an intrastate 

pipeline to provide interstate service 

‘‘shall be under such terms and 

conditions as the Commission may 

prescribe.’’ 29 Section 284.224 of the 

Commission’s regulations provides for 

the issuance of blanket certificates 

under section 7 of the NGA to Hinshaw 

pipelines 30 to provide open access 

transportation service ‘‘to the same 

extent that and in the same manner’’ as 

intrastate pipelines are authorized to 

perform such service.31 The 

Commission regulates the rates for 

interstate service provided by Hinshaw 

pipelines under NGA sections 4 and 5. 

17. Section 284.123 of the 

Commission’s regulations provides 

procedures for NGPA section 311 and 

Hinshaw pipelines to establish fair and 

equitable rates for their interstate 

services.32 Section 284.123(b) allows 

intrastate pipelines an election of two 

different methodologies upon which to 

base their rates for interstate services.33

First, § 284.123(b)(1) permits an 

intrastate pipeline to elect to base its 

rates on the methodology or rate(s) 

approved by a state regulatory agency 

included in an effective firm rate for 

city-gate service. Second, § 284.123(b)(2) 

provides that the pipeline may petition 

for approval of rates and charges using 

its own data to show its proposed rates 

are fair and equitable. The Commission 

has established a policy of reviewing the 

rates of NGPA section 311 and Hinshaw 

pipelines every five years.34 Section 311 

pipelines not using state-approved rates 

must file a new rate case every five 

years, and Hinshaw pipelines must at a 

minimum file a cost and revenue study 

every five years. Intrastate pipelines 


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35Petitioners include the following trade 

associations: American Forest and Paper 

Association, American Public Gas Association, 

Independent Petroleum Association of America, 

Natural Gas Supply Association, and Process Gas 

Consumers Group. Petitioners also include the 

following companies: Aera Energy LLC, Anadarko 

Energy Services Company, Chevron U.S.A. Inc., 

ConocoPhillips Company, Hess Corporation, 

Petrohawk Energy Corporation, WPX Energy 

Marketing, LLC, and XTO Energy Inc. 

36 15 U.S.C. 717i(a), 717m(a). 

37NOPR, FERC Stats. & Regs. ¶ 32,725 at P 32. 

The One-time Report on Rate Effect of the Tax Cuts 

and Jobs Act is referred to interchangeably as ‘‘Onetime Report’’ or ‘‘FERC Form No. 501–G’’ in this 

Final Rule. 

38NOPR, FERC Stats. & Regs. ¶ 32,725 at PP 41– 

51. 

39 Id. PP 4, 40 & n.8. 

40The list of commenters and the abbreviation 

used for each in this order are shown on 

Appendix A. 

using state-approved rates that have not 

changed since the previous five-year 

filing are only required to make a filing 

certifying that those rates continue to 

meet the requirements of § 284.123(b)(1) 

on the same basis on which they were 

approved. Conversely, if the stateapproved rate used for the election is 

changed at any time, the NGPA section 

311 or Hinshaw pipeline must file a 

new rate election pursuant to 

§ 284.123(b) for its interstate rates no 

later than 30 days after the changed rate 

becomes effective. 

18. An intrastate pipeline may file to 

request authorization to charge marketbased rates under subpart M of Part 284 

of the Commission’s regulations. The 

same requirements for showing a lack of 

market power apply to intrastate 

pipelines as for interstate pipelines. The 

Commission has granted market-based 

rate authority for storage and hub 

services to 19 of the 112 intrastate 

pipelines with subpart C of Part 284 

tariffs. 

D. Request for Commission Action 

19. On January 31, 2018, in Docket 

No. RP18–415–000, several trade 

associations and companies 

representing a coalition of the natural 

gas industry that are dependent upon 

services provided by interstate natural 

gas pipeline and storage companies 

(Petitioners) 35 filed a petition 

requesting that the Commission take 

immediate action under sections 5(a), 

10(a), and 14(a) and (c) of the NGA to 

initiate show cause proceedings against 

all interstate natural gas pipeline 

companies (with certain exceptions) and 

require each pipeline to submit a cost 

and revenue study to demonstrate that 

its existing jurisdictional rates continue 

to be just and reasonable following the 

passage of the Tax Cuts and Jobs Act. 

20. Petitioners requested that the 

Commission require an immediate rate 

reduction, if a filed cost and revenue 

study demonstrates that the interstate 

natural gas pipeline is over-recovering 

its costs following the adjustments to 

account for changes to the tax laws 

implemented under the Tax Cuts and 

Jobs Act. Petitioners contended that, if 

a pipeline believed that a Commissionapproved settlement exempted it from 

such a rate analysis, the Commission 

should require such company to provide 

evidence to that effect. 

E. Notice of Proposed Rulemaking 

21. In response to the Tax Cuts and 

Jobs Act and United Airlines Issuances, 

on March 15, 2018, the Commission 

issued a NOPR proposing to require 

interstate natural gas pipelines to file an 

informational filing with the 

Commission pursuant to sections 10(a) 

and 14(a) of the NGA 36 (One-time 

Report on Rate Effect of the Tax Cuts 

and Jobs Act, FERC Form No. 501–G).37

The One-time Report was designed to 

collect financial information to evaluate 

the impact of the Tax Cuts and Jobs Act 

and United Airlines Issuances on 

interstate natural gas pipelines’ revenue 

requirements. In addition to the Onetime Report, the Commission proposed 

to provide four options for each 

interstate natural gas pipeline to choose 

from, including to voluntarily make a 

filing to address the changes to the 

pipeline’s recovery of tax costs, or 

explain why no action is needed. The 

four options are: (1) File a limited NGA 

section 4 filing to reduce the pipeline’s 

rates to reflect the decrease in the 

federal corporate income tax rate 

pursuant to the Tax Cuts and Jobs Act 

and the elimination of the income tax 

allowance for MLP pipelines consistent 

with the Revised Policy Statement, (2) 

make a commitment to file a general 

NGA section 4 rate case in the near 

future, (3) file a statement explaining 

why an adjustment to its rates is not 

needed, or (4) take no action other than 

filing the One-time Report. If an 

interstate natural gas pipeline does not 

choose either of the first two options, 

the Commission would consider, based 

on the information in the One-time 

Report and comments by interested 

parties, whether to issue an order to 

show cause under NGA section 5 

requiring the pipeline either to reduce 

its rates to reflect the income tax 

reduction or explain why it should not 

be required to do so.38

22. The Commission proposed to 

establish a staggered schedule for 

interstate natural gas pipelines to file 

the One-time Report and choose one of 

the four options described above. The 

Commission stated in the NOPR that 

interstate natural gas pipelines that file 

general NGA section 4 rate cases or prepackaged uncontested rate settlements 

before the deadline for their One-time 

Report will be exempted from making 

the One-time Report. In addition, the 

Commission stated that interstate 

natural gas pipelines whose rates are 

being investigated under NGA section 5 

need not file the One-time Report.39

F. Comments on Notice of Proposed 

Rulemaking 

23. The Commission received 33 

comments and ten answers and reply 

comments in response to its NOPR.40 In 

general, commenters support the 

Commission taking action in regard to 

the recent tax changes although 

commenters disagree about various 

aspects of the Commission’s proposed 

procedures. These comments have 

informed our determinations in this 

Final Rule. 

24. Several commenters take issue 

with the NOPR’s implementation of the 

Revised Policy Statement and the 

proposal that, if an MLP pipeline 

chooses the option of making a limited 

NGA section 4 filing, that filing must 

reduce its maximum rates to reflect the 

elimination of any tax allowance 

included in its current rates consistent 

with the Revised Policy Statement. 

25. In regard to the proposed FERC 

Form No. 

501–G, among other things, commenters 

challenge the Commission’s authority to 

require such a filing, seek clarification 

regarding inputs to the form including 

the use of an indicative ROE of 10.55 

percent, and suggest changes to the 

form. 

26. Commenters also seek clarification 

and suggest changes to the four options 

for an interstate natural gas pipeline to 

make a filing to address the changes to 

the pipeline’s recovery of tax costs or 

explain why no action is needed. 

Commenters suggest alternative 

timelines or request additional time to 

make such filings. Commenters also 

seek clarification regarding the deadline 

to make such filings. Some commenters 

suggest that the Commission eliminate 

or alter some of the proposed filing 

options. 

27. The Commission also received 

several comments regarding negotiated 

rate agreements and whether those 

agreements can or should be altered by 

the Final Rule. 

28. Commenters generally support the 

Commission’s proposed procedures for 

NGPA section 311 and Hinshaw 

pipelines with some suggested 

modifications. 


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41 Inquiry Regarding the Commission’s Policy for 

Recovery of Income Tax Costs, Order on Rehearing, 

164 FERC ¶ 61,030 (2018). 

III. Overview of Final Rule 

29. In this Final Rule, the Commission 

adopts procedures for determining 

which jurisdictional natural gas 

pipelines may be collecting unjust and 

unreasonable rates in light of (1) the 

income tax reductions provided by the 

Tax Cuts and Jobs Act and (2) the 

United Airlines Issuances. These 

procedures also allow interstate natural 

gas pipelines to voluntarily reduce their 

rates to reflect the income tax 

reductions and change in tax allowance 

resulting from the United Airlines 

Issuances. 

30. The Commission adopts, with 

modifications, the procedures proposed 

in the NOPR. The Final Rule establishes 

a requirement, pursuant to sections 10 

and 14(a) of the NGA, that all interstate 

natural gas companies, with cost-based 

stated rates, that filed a 2017 FERC 

Form No. 2 or 2–A must file the FERC 

Form No. 501–G informational filing for 

the purpose of evaluating the impact of 

the Tax Cuts and Jobs Act and the 

United Airlines Issuances on interstate 

natural gas pipelines’ revenue 

requirements. The Final Rule makes 

certain adjustments to the FERC Form 

No. 501–G. For example, if a pipeline 

states that it is not a tax paying entity, 

the revised form will not only 

automatically enter a federal and state 

income tax of zero, but also eliminate 

ADIT from the pipeline’s cost of service. 

This change is consistent with the 

policy announced in our 

contemporaneous order on rehearing of 

the Revised Policy Statement,41 that 

when a pass-through entity’s tax 

allowance is eliminated, it is 

appropriate to also eliminate ADIT. The 

Final Rule also modifies the FERC Form 

No. 501–G’s treatment of capital 

structure, so that, among other things, if 

a pipeline must report a hypothetical 

capital structure, that capital structure 

will be 57 percent equity, instead of 50 

percent equity. 

31. In addition to the FERC Form No. 

501–G filing requirement, the 

Commission provides four options for 

each interstate natural gas pipeline to 

make a filing to address the changes to 

the pipeline’s recovery of tax costs or 

explain why no action is needed: (1) A 

limited NGA section 4 rate reduction 

filing (Option 1), (2) a commitment to 

file a general section 4 rate case in the 

near future (Option 2), (3) an 

explanation why no rate change is 

needed (Option 3), and (4) no action 

(Option 4). These procedures are 

intended to encourage natural gas 

pipelines to voluntarily reduce their 

rates to the extent the tax changes result 

in their over-recovering their cost of 

service, while also providing the 

Commission and stakeholders 

information necessary to take targeted 

actions under NGA section 5 where 

necessary to achieve just and reasonable 

rates. 

32. We modify the NOPR proposal so 

as to permit MLP pipelines to, under 

Option 1, propose in their limited 

section 4 filings to either (1) eliminate 

their tax allowance, along with their 

ADIT, or (2) reflect only the tax 

reductions in the Tax Cuts and Jobs Act. 

Although the Commission determined 

in the Revised Policy Statement that 

permitting MLP pipelines to include a 

tax allowance in their cost of service 

results in a double recovery of the MLP 

pipeline’s tax costs, the Commission 

will not require MLP pipelines to 

eliminate their tax allowances in this 

rulemaking proceeding. The Final Rule 

also clarifies that a natural gas company 

organized as a pass-through entity is 

considered subject to the federal 

corporate income tax, if all of its income 

or losses are consolidated on the federal 

income tax return of its corporate 

parent. Thus, such a pass-through entity 

is eligible for a tax allowance. 

33. The Commission reiterates the 

voluntary nature of the three filing 

options and the option to take no action 

available to pipelines once the pipeline 

files the required FERC Form No. 501– 

G. While the Commission is permitting 

interstate natural gas pipelines to 

voluntarily file a limited NGA section 4 

filing or commit to make a general NGA 

section 4 rate case filing to modify their 

rates to reflect the impact of the Tax 

Cuts and Jobs Act and United Airlines 

Issuances, the Commission is not 

ordering interstate natural gas pipelines 

to make such filings. The limited NGA 

section 4 filing option (Option 1) is 

beneficial to both pipelines and their 

customers because it allows interstate 

pipelines to voluntarily reduce their 

rates to reflect a reduction in a single 

cost component—their federal income 

tax costs—so as to flow through that 

benefit to consumers as soon as 

possible. In order to provide an 

additional incentive for pipelines to 

make a limited NGA section 4 rate 

reduction filing, the Final Rule includes 

a guarantee that the Commission will 

not, for a three-year moratorium period, 

initiate a NGA section 5 rate 

investigation of a pipeline that makes 

such a filing, if that filing reduces the 

pipeline’s ROE to 12 percent or less. 

34. The commitment to file a general 

NGA section 4 rate case in the near 

future option (Option 2) provides an 

opportunity for pipelines to reflect the 

impact of the Tax Cuts and Jobs Act and 

United Airlines Issuances if the limited 

NGA section 4 filing option would not 

be appropriate. Although the 

Commission prefers for pipelines to 

reflect the impact of the Tax Cuts and 

Jobs Act and United Airlines Issuances 

on their own accord, the Commission 

will consider whether to initiate an 

investigation to determine if the 

pipeline’s rates may be unjust and 

unreasonable under NGA section 5 if a 

pipeline that chooses Option 3 (provide 

an explanation why no rate change is 

needed) fails to convince the 

Commission, or the pipeline chooses 

Option 4 (take no action). 

35. The Commission also modifies the 

implementation schedule proposed in 

the NOPR by combining the third and 

fourth groups of pipelines into a single 

group. The deadline for the first group 

of pipelines to file their FERC Form No. 

501–Gs will be 28 days after the 

effective date of the Final Rule and the 

deadlines for the second and third 

groups will each be 28 days after the 

previous group’s deadline. Combining 

the third and fourth groups into a single 

group will allow the filing of the FERC 

Form No. 501–Gs to be completed by 

early December of this year. 

36. Additionally, the Commission 

adopts, with clarifying modifications, 

the procedures proposed in the NOPR 

for NGPA section 311 and Hinshaw 

pipelines to reflect in their 

jurisdictional rates any rate reductions 

from the Tax Cuts and Jobs Act and the 

United Airlines Issuances directed by a 

state agency. Pursuant to this Final 

Rule, NGPA section 311 and Hinshaw 

pipelines are not required to file the 

FERC Form No. 501–G or make any 

other immediate filing. Instead, the 

Commission will rely on its five-year 

rate review process as the primary 

mechanism to consider changes to 

reflect the Tax Cuts and Jobs Act, and 

the Commission adopts the NOPR’s 

proposed § 284.123(i) in this Final Rule. 

Under pre-existing policy, any pipeline 

that elected to use state-derived rates 

pursuant to § 284.123(b)(1) is already 

required to file with the Commission a 

new rate election 30 days after a state 

regulatory agency adjusts its intrastate 

rates, and new § 284.123(i) expands that 

requirement to include intrastate 

pipelines that use Commissionestablished cost-based rates pursuant to 

§ 284.123(b)(2), as well as pipelines that 

use state derived rates pursuant to 

§ 284.123(b)(1). 


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42NOPR, FERC Stats. & Regs. ¶ 32,725 at P 42. 

43 Id. P 36. 

44NGSA Comments at 3, 5. 

45APGA Comments at 5–7. 

46CAPP Comments at 3–4, 7. 

47 Direct Energy Comments at 7. 

48CAPP Comments at 7. 

49 INGAA Comments at 3, 11, 15, 17–18; 

Boardwalk Comments at 2; Spectra Comments at 

16–17, 28; Kinder Morgan Comments at 21–23; 

Williams Comments at 4, 14; Millennium 

Comments at 1–2; Dominion Energy Comments at 

2, 9; Enable Interstate Pipelines Comments at 28– 

31. 

50 INGAA Comments at 3, 11, 18–19; Boardwalk 

Comments at 2, 5; Spectra Comments at 4–5; 

Williams Comments at 14; Millennium Comments 

at 1–2. 

51 INGAA Comments at 2–3; Boardwalk 

Comments at 2; Williams Comments at 4, 12; 

Millennium Comments at 1; Tallgrass Pipelines 

Comments at 10; Dominion Energy Comments 

at 5–7. 

52 INGAA Comments at 16–18; Williams 

Comments at 4, 14–15; Millennium Comments at 1. 

53 INGAA, Enable, Spectra, Kinder Morgan, 

Tallgrass Pipelines, EQT Midstream, and Dominion 

Energy filed requests for rehearing of the Revised 

Policy Statement in Docket No. PL17–1. 

54 Dominion Energy Comments at 3; INGAA 

Comments at 2. 

55Tallgrass Pipelines Comments at 4–9; EQT 

Midstream Comments at 2, 6–8. 

56 INGAA Comments at 3; Boardwalk Comments 

at 2; Tallgrass Pipelines Comments at 4–9; EQT 

Midstream Comments at 2, 6–8. 

IV. Discussion 

A. Treatment of Pass-Through Entities 

1. NOPR 

37. The NOPR addressed the 

treatment of pass-through entities in two 

ways. First, the proposed One-time 

Report, FERC Form No. 501–G, assumed 

a federal and state income tax allowance 

of zero for all pass-through entities in 

order to address the double-recovery 

issues discussed in the United Airlines 

Issuances. 

38. Second, the implementation of 

Option 1, described above, provided 

different treatment for MLP pipelines as 

compared to other entities, as set forth 

in proposed § 154.404 of the 

regulations.42 Specifically, proposed 

§ 154.404 distinguishes between the 

types of rate reductions pipelines could 

include in these limited NGA section 4 

filings, depending upon whether the 

pipeline should be treated as a 

corporation, an MLP pipeline, or a nonMLP partnership. Thus, proposed 

§ 154.404(a)(1) permits a pipeline 

subject to the federal corporate income 

tax to make a limited NGA section 4 

filing reducing its maximum rates to 

reflect the decrease in the federal 

corporate income tax rate pursuant to 

the Tax Cuts and Jobs Act. However, 

proposed § 154.404(a)(2) only permits 

an MLP pipeline to file a limited NGA 

section 4 filing reducing its maximum 

rates to reflect the elimination of any tax 

allowance included in its current rates 

consistent with the United Airlines 

Issuances. In contrast, proposed 

§ 154.404(a)(3) provides that if a 

partnership not organized as an MLP 

pipeline believes that a federal or state 

income tax allowance is permissible 

notwithstanding United Airlines, it may 

justify why its pipeline should continue 

to receive an income tax allowance and 

reduce its maximum rates to reflect the 

decrease in the federal income tax rates 

applicable to partners pursuant to the 

Tax Cuts and Jobs Act.43

2. Comments 

39. Some commenters support the 

implementation of the Revised Policy 

Statement in the proposed rule, 

including NGSA,44 APGA,45 CAPP,46

and Direct Energy.47 CAPP supports the 

proposal that pass-through entities 

report a federal and state income tax 

expense of zero on the proposed FERC 

Form No. 501–G, unless a non-MLP 

partnership can justify why it should 

continue to receive an income tax 

allowance while reducing its maximum 

rates to reflect the decrease in the 

federal income tax rates resulting from 

the Tax Cuts and Jobs Act. CAPP asserts 

that such information will enable 

shippers and the Commission to 

properly evaluate submissions by 

pipelines as to whether adjustments to 

rates are appropriate in light of the tax 

changes and, in the absence of any 

pipeline commitments to changing 

rates, whether an NGA section 5 review 

of rates is warranted.48 APGA asserts 

that the proposed rule is an appropriate 

response to pipelines that seek 

clarification of the Revised Policy 

Statement because pipelines can 

demonstrate the applicability of the 

Commission’s revised policy to their 

own situations. 

40. Several commenters representing 

pipeline interests oppose the 

implementation of the Revised Policy 

Statement in the proposed rule, 

including INGAA, Enable Interstate 

Pipelines, Boardwalk, Spectra, Kinder 

Morgan, Williams, Millennium, and 

Dominion Energy. These commenters 

request that the Commission remove the 

requirements that MLP pipelines and 

other pass-through pipelines (1) report 

an income tax expense of zero in the 

FERC Form No. 501–G and (2) eliminate 

a tax allowance in making a limited 

section 4 rate reduction filing.49 These 

commenters also request that the 

Commission clarify that pass-through 

pipelines, including MLP pipelines, will 

be allowed to propose and present 

evidence supporting an income tax 

allowance in future rate proceedings.50

To support these positions, the 

pipelines (a) raise various challenges to 

the Commission’s response to United 

Airlines and (b) identify various 

concerns with the implementation of 

those policies in the NOPR. These 

arguments, and various requests for 

clarification, are discussed below. 

a. Challenges to the Commission’s 

Response to United Airlines 

41. Pipeline commenters argue that 

the Revised Policy Statement is not a 

binding rule with the force of law.51

They assert that under the 

Administrative Procedure Act, the 

Commission must support the policy 

with substantial evidence as if it had 

never been issued in order to apply the 

policy as a substantive rule in this 

proceeding and the Commission has not 

done so.52

42. In addition, several pipeline 

commenters challenge the 

Commission’s Revised Policy Statement 

and Opinion No. 511–C, including 

INGAA, Enable Interstate Pipelines, 

Boardwalk, Spectra, Kinder Morgan, 

Williams, Tallgrass Pipelines, EQT 

Midstream, and Dominion Energy.53

These commenters assert that the 

Revised Policy Statement was not the 

product of reasoned decision-making.54

Other commenters request that the 

Commission resolve similar issues 

raised in requests for rehearing of the 

Revised Policy Statement before natural 

gas pipelines are required to file any 

information regarding the effects upon 

the pipeline’s cost of service.55

43. Pipeline commenters argue that 

implementing the Revised Policy 

Statement in this rulemaking 

proceeding will introduce uncertainty 

that will delay resolution of the action 

to address the rate impact from the Tax 

Cuts and Jobs Act. They state that 

removing the MLP pipeline and passthrough income tax allowance issues 

from the proposed rule will reduce the 

uncertainty associated with the 

proposed rule and allow pipelines and 

their customers to focus on the potential 

rate reductions resulting from the Tax 

Cuts and Jobs Act.56

b. Arguments Regarding the 

Implementation 

44. Commenters also raise concerns 

and request clarification regarding the 

NOPR’s proposed implementation of the 

Revised Policy Statement. 

45. First, pipeline commenters argue 

that the proposed rule improperly 

places the burden under NGA section 5 


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57 INGAA Comments at 19–22; Enable Interstate 

Pipelines Comments at 25–26; Kinder Morgan 

Comments at 19; Williams Comments at 11; 

Millennium Comments at 7–8; TransCanada 

Comments at 9. 58APGA Comments at 6. 59 Id. 60 INGAA Comments at 21; Enable Interstate 

Pipelines Comments at 25–26; Spectra Comments at 

5, 12, 18–20; Kinder Morgan Comments at 14–23; 

Williams Comments at 4, 11; Millennium 

Comments at 7–9; TransCanada Comments at 8–10; 

Tallgrass Pipelines Comments at 10–11; EQT 

Midstream Comments at 6–7; Dominion Energy 

Comments at 5–6. 61 INGAA Comments at 19–21; Enable Interstate 

Pipelines Comments at 33; Kinder Morgan 

Comments at 17–18, 21–23; Millennium Comments 

at 5–6. 

62 INGAA Comments at 19–21; Enable Interstate 

Pipelines Comments at 25–26, 33; Spectra 

Comments at 12; Kinder Morgan Comments at 2, 

17–23; Williams Comments at 11; Millennium 

Comments at 5–7, 9; TransCanada Comments at 3, 

8–9; Tallgrass Pipelines Comments at 10–11; EQT 

Midstream Comments at 6–7. 

63 INGAA Comments at 21; Millennium 

Comments at 6–7. 

64 INGAA Comments at 21; Spectra Comments at 

18–19; Millennium Comments at 9; Tallgrass 

Pipelines Comments at 10–11; Kinder Morgan 

Comments at 15. 

65 Kinder Morgan Comments at 15. 

66Millennium Comments at 5–6. 

67AGA Comments at 5–6. 

68Spectra Comments at 28–29. 

69A pass-through entity or pipeline refers to an 

entity that does not pay taxes itself. As discussed 

below, in the Final Rule we are revising § 154.404 

to provide that a natural gas company organized as 

a pass-through entity whose income or losses are 

included in the consolidated federal income tax 

return of its corporate parent is considered to be 

subject to the federal corporate income tax. 

onto pass-through entities to justify a 

tax allowance.57

46. Second, while generally 

supporting the proposal, APGA also 

claims that proposed § 154.404(a)(3) 

should be amended to replace 

‘‘partnership’’ with ‘‘partnership or 

other pass-through entity.’’ APGA 

argues that the proposed NOPR 

recognizes that partnerships or other 

pass-through entities such as limited 

liability corporations must address the 

double-recovery concern raised by 

United Airlines.58 APGA also proposes 

that the Commission clarify that if a 

pass-through entity files a written 

justification to preserve its tax 

allowance under the limited section 4 

option (Option 1), staff and intervenors 

may comment or seek a hearing on that 

issue. APGA proposes to add a new 

subpart (iv) to § 154.404(e) that states 

‘‘Whether any justification submitted 

pursuant to paragraph (a)(3)(ii) of this 

section is consistent with Commission 

policy and the public interest.’’ 59

47. Finally, several pipeline 

commenters challenge the FERC Form 

No. 501–G’s assumption that a non-MLP 

pass-through pipeline’s federal and state 

tax allowance is zero.60 They request 

that the Commission clarify that nonMLP pass-through entities, in particular 

those that are owned, in whole or in 

part, by tax-paying corporate partners, 

may continue to recover an income tax 

allowance.61 These commenters argue 

that the assumed tax allowance of zero 

for pass-through entities is unwarranted 

given that the Revised Policy Statement 

and § 154.404(a)(3) of the proposed rule 

explicitly permit a non-MLP passthrough entity to justify why it should 

continue to receive an income tax 

allowance.62 They further claim that 

assuming a tax allowance of zero for all 

pass-through pipelines will result in 

inaccuracies and distortions of such 

pipeline’s reported cost of service on the 

FERC Form No. 501–G. They allege that 

such distortions could discourage 

pipelines from making the limited 

section 4 filings,63 lead customers to 

mistakenly conclude that these 

pipelines are over-earning,64 and hinder 

settlement negotiations between 

pipelines and shippers.65

48. Regarding non-MLP pass-through 

entities, commenters support these 

concerns with specific arguments and 

requests for clarification. For instance, 

arguing that there is no double-recovery 

when a pass-through entity is owned by 

a corporation, Millennium requests that 

a partnership be permitted to include an 

income tax allowance on the FERC 

Form No. 501–G and in the limited 

section 4 filings if such entity is owned 

by corporations that incur an income tax 

liability before issuing dividends to 

their shareholders.66 AGA requests that 

the Commission clarify the proper 

reporting on FERC Form No. 501–G for 

a non-MLP pass-through pipeline that is 

partly owned by at least one MLP and 

partly owned by one or more 

corporations.67 Similarly, Spectra 

requests that the Commission revise the 

FERC Form No. 501–G to allow joint 

venture pipelines to include an income 

tax allowance or to reflect such 

pipeline’s ownership in the cost-ofservice components.68

3. Discussion 

49. As discussed below, the 

Commission is revising proposed 

§ 154.404 so that MLP pipelines, like 

other pass-through entities,69 that 

choose Option 1 (limited section 4 rate 

filing) may reduce their rates solely to 

reflect the Tax Cuts and Jobs Act 

without further reducing rates for the 

elimination of the income tax 

allowance. The Commission also 

provides clarification regarding the 

completion of FERC Form No. 501–G 

and the permissible adjustments. 

50. Given these modifications, the 

Commission is not, in this rulemaking 

proceeding, addressing the merits of 

either (1) the Commission’s holding in 

Opinion No. 511–C that an 

impermissible double recovery results 

from granting an MLP pipeline both an 

income tax allowance and a DCF ROE 

or (2) the similar policy the Commission 

announced in the Revised Policy 

Statement. However, the binding 

precedent of United Airlines and 

Opinion No. 511–C may be considered 

by the Commission or any shipper when 

initiating any subsequent section 5 

action, and we encourage pipelines to 

consider the guidance provided by the 

Revised Policy Statement. 

a. Limited Section 4 Filings 

51. In the Final Rule, the Commission 

modifies the proposed § 154.404(a) 

permitting limited section 4 rate filings 

as follows [deletions in italics, additions 

in underline]: 


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70As discussed below, the Commission 

acknowledges that the Revised Policy Statement’s 

elimination of an income tax allowance for MLP 

pipelines is not a binding rule, but an expression 

of policy intent following the United Airlines 

decision. Pacific Gas & Electric Co. v. FPC, 506 F.2d 

33, 38 (D.C. Cir. 1974). 

71 In Pacific Gas & Electric Co., 506 F.2d at 33, 

38, the D.C. Circuit stated that the Commission may 

‘‘establish binding policy . . . through 

adjudications which constitute binding precedent.’’ 

See Algonquin Gas Transmission, LLC, 153 FERC 

¶ 61,038, at PP 29–37 (2015), and cases cited. 

Although Opinion No. 511–C is pending rehearing, 

it remains binding precedent. 

52. Pursuant to these revisions to 

§ 154.404(a), MLP pipelines will have 

the same options as other pass-through 

entities in a limited section 4 rate filing: 

Either to reduce their rates to reflect 

complete elimination of the tax 

allowance or to reduce their rates only 

for the Tax Cuts and Jobs Act without 

further reducing rates for the 

elimination of their income tax 

allowance. Likewise, consistent with the 

discussion in section IV.B.7, the 

Commission is also modifying the 

proposed § 154.404 so that a pipeline’s 

limited NGA section 4 filing can reflect 

the elimination of ADIT as a result of 

the elimination of an income tax 

allowance. 

53. The Commission expects that 

modifying proposed § 154.404(a) in this 

manner will help achieve Commission 

objectives. The Commission seeks to 

encourage MLP pipelines (like all other 

pipeline entities) to quickly reduce rates 

and to pass on the benefits of reduced 

tax costs to customers without the need 

for a full examination of costs and 

revenues. Allowing MLP pipelines the 

option to make a rate reduction 

reflecting reduced tax rates under the 

Tax Cuts and Jobs Act while still 

asserting eligibility for a tax allowance 

will incentivize more pipelines to file 

the limited section 4 rate cases. 

Additionally, MLP pipelines and other 

pass-through entities making the limited 

section 4 filing would be eligible for the 

moratoria on NGA section 5 rate 

investigations discussed below. 

Although in a subsequent proceeding 

the Commission (subject to the 

moratoria) or any shipper may take 

action under NGA section 5 to further 

reduce an MLP pipeline’s rates, we 

believe providing pipelines flexibility in 

the limited NGA section 4 filing option 

will increase the probability that 

customers benefit from an immediate 

rate reduction.70

54. Furthermore, we seek to avoid 

complicating the optional, limited NGA 

section 4 proceedings. We recognize 

that the Revised Policy Statement itself 

is guidance, not binding precedent. 

Although United Airlines and Opinion 

No. 511–C are binding precedent,71

SFPP has sought rehearing of that order, 

and other pipelines have raised issues 

involving the Commission’s income tax 

policies for pass-through entities in 

comments in response to the NOPR. We 

decline to address such matters in this 

rulemaking proceeding, particularly 

when the Commission will be able to 

address these United Airlines issues, as 

appropriate, when we address the 

pending request for rehearing of 

Opinion No. 511–C and in any ensuing 

NGA section 5 investigation after 

pipelines file their FERC Form No. 501– 

Gs as discussed below. 

55. Consistent with the modifications 

discussed above, we clarify that an MLP 

pipeline or other pass-through entity’s 

decision to submit an optional limited 

NGA section 4 rate filing to reduce rates 

for the Tax Cuts and Jobs Act, as 

opposed to eliminating its income tax 

allowance, is not an issue that is within 

the scope of the limited NGA section 4 

proceeding. Permitting parties to 

challenge a pass-through entity’s choice 

to not eliminate its income tax 

allowance through its limited NGA 

section 4 rate filing would undermine 

the Commission’s objectives in affording 

pass-through entities both options in the 

first place, namely to encourage more 

entities to file limited NGA section 4 

rate cases and expedite rate reductions. 

If an MLP pipeline or other passthrough entity chooses to make the more 

limited rate reduction reflecting reduced 

tax rates under the Tax Cuts and Jobs 

Act, the issue of whether a further rate 

reduction is just and reasonable because 

the entity should not recover any 

income tax allowance may arise in a 

subsequent NGA section 5 proceeding, 

subject to the moratoria provisions 

regarding Commission-initiated section 


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72BP West Coast Products, LLC v. FERC, 374 F.3d 

1263, at 1289 (D.C. Cir. 2004) (explaining that an 

income tax allowance is appropriate in the cost of 

service of a pass-through subsidiary of a corporation 

‘‘when such a subsidiary does not itself incur a tax 

liability but generates one that might appear on a 

consolidated return of the corporate group.’’). 

73Similarly, when filling out the FERC Form No. 

501–G, such a natural gas company may state that 

it is a tax paying entity, and thus, as discussed 

below, the form will not automatically enter a 

federal and state income tax of zero. 

74However, as discussed below, consistent with 

the language the Commission is adding to 

154.404(b)(1), a natural gas company organized as 

a pass-through entity all of whose income or losses 

are consolidated on the federal income tax return 

of its corporate parent is considered to be subject 

to the federal corporate income tax for purposes of 

the FERC Form No. 501–G, and therefore the form 

will not automatically enter a federal and state 

income tax of zero for such a natural gas company. 

BP West Coast Products, LLC v. FERC, 374 F.3d 

1263, at 1289 (D.C. Cir. 2004). 

75As explained below, whether or not the 

pipeline uses FERC Form No. 501–G or the optional 

Addendum, the limited NGA section 4 rate filing 

should only reflect the percent change to the 

pipeline’s cost of service resulting from the 

reduction in the pipeline’s income tax allowance 

and any corresponding adjustment to ADIT. In the 

limited NGA section 4 filing, the pipeline cannot 

treat other cost changes as offsetting the reduction 

to the income tax allowance. 

76United Airlines, 827 F.3d 122 at 134, 136. 

77Opinion No. 511–C, 162 FERC ¶ 61,228. 

78The income tax allowance attributable to 

individual unit holders should reflect the reduction 

in the tax rate applicable to the taxpayer(s) and 

include any adjustment for the deduction for 

section 199A ‘‘qualified business income of passthru entities’’ pursuant to the Tax Cuts and Jobs 

Act. See Tax Cuts and Jobs Act 11011, 131 Stat. at 

2063. 

79See, e.g., IRS Form 851: Affiliations Schedule; 

IRS Form 1122: Authorization and Consent of 

Subsidiary Corporation To Be Included in a 

Consolidated Income Tax Return. 

80See, e.g., Millennium Comments at 5–6; AGA 

Comments at 5–6. 

5 proceedings discussed below. 

Nonetheless, the Commission 

encourages MLP pipelines to consider 

the guidance provided in the Revised 

Policy Statement as well as the 

precedents of United Airlines and 

Opinion No. 511–C in evaluating the 

options available in § 154.404. 

56. In response to the comments, the 

Commission also provides other 

clarifications regarding the limited NGA 

section 4 filings. In response to 

comments from APGA, we clarify that 

§ 154.404 applies to all pass-through 

entities (such as limited liability 

corporations), not merely partnerships, 

and we have modified § 154.404 to 

replace the reference to ‘‘partnership’’ 

with ‘‘pass-through entity.’’ We also add 

language in § 154.404(b) to clarify that, 

for purposes of making a limited NGA 

section 4 filing under § 154.404(a), a 

natural gas company organized as a 

pass-through entity all of whose income 

or losses are consolidated on the federal 

income tax return of its corporate parent 

is considered to be subject to the federal 

corporate income tax.72 Thus, such a 

natural gas company may make its 

limited NGA section 4 filing pursuant to 

§ 154.404(a)(1), which is applicable to 

natural gas companies subject to the 

federal corporate income tax, rather 

than under § 154.404(a)(2), which is 

applicable to pass-through entities.73

57. In addition, the Commission 

eliminates any requirement as a part of 

the limited NGA section 4 filing for a 

pass-through entity to satisfy a burden 

of showing that it is entitled to receive 

any income tax allowance. The 

Commission recognizes that it will have 

the burden, in any proceeding it 

initiates under NGA section 5 to support 

complete elimination of the existing tax 

allowance. Moreover, as discussed 

below, any pass-through entity reporting 

an income tax allowance in an optional 

Addendum to FERC Form No. 501–G 

may provide such explanation. 

b. FERC Form No. 501–G and 

Addendum 

58. Although the Commission will 

permit all pass-through entities to make 

limited NGA section 4 filings which 

only reduce their rates to reflect the 

reduced income tax rates in the Tax 

Cuts and Jobs Act, the Commission is 

continuing to design the FERC Form No. 

501–G so that it will automatically enter 

a federal and state income tax of zero for 

all respondents that state they are not 

tax paying entities.74 However, we 

clarify that a pass-through entity 

claiming a tax allowance may submit an 

Addendum to the FERC Form No. 501– 

G that includes an income tax 

allowance. Moreover, consistent with 

the discussion above, to the extent a 

pipeline elects to make the optional 

limited NGA section 4 filing, the 

pipeline may use either (a) the FERC 

Form No. 501–G if it proposes to 

eliminate its tax allowance or (b) the 

Addendum to the FERC Form No. 501– 

G if it claims a tax allowance.75

59. The FERC Form No. 501–G will 

continue to require pass-through entities 

to report an income tax allowance of 

zero, because this informational filing is 

intended to aid the Commission’s 

further evaluation of a pipeline’s cost of 

service given the double-recovery 

concerns raised by United Airlines 76

and Opinion No. 511–C.77 This 

precedent provides that an MLP cannot 

claim an income tax allowance if a 

double-recovery results from the 

inclusion of both (a) a DCF ROE and (b) 

an income tax allowance. Although the 

Commission is not adopting the NOPR 

proposal to require MLP pipelines to 

eliminate their tax allowances in any 

limited NGA section 4 filing, Opinion 

No. 511–C remains binding Commission 

precedent. Accordingly, if a passthrough entity files a limited NGA 

section 4 filing reducing its rates to 

reflect the Tax Cuts and Jobs Act 

without proposing to eliminate its tax 

allowance, the Commission will 

consider whether to initiate an NGA 

section 5 investigation to further reduce 

the pipeline’s rates by eliminating its 

tax allowance consistent with Opinion 

No. 511–C and United Airlines, subject 

to the moratoria provisions regarding 

Commission-initiated section 5 

proceedings discussed below. In 

addition, shippers have the option of 

bringing a complaint under NGA section 

5 and raising arguments based upon the 

United Airlines Issuances. The 

elimination of the income tax allowance 

in the FERC Form No. 501–G will help 

the Commission and pipeline customers 

assess the potential effects of the 

removal of any income tax allowance as 

a consequence of United Airlines’ 

double-recovery concerns. 

60. However, in an Addendum to 

FERC Form No. 501–G that pipelines 

may choose to file along with their 

FERC Form No. 501–G, the Commission 

will permit pass-through entities to 

report an income tax allowance 

alongside the other adjustments to FERC 

Form No. 501–G. Any income tax 

allowance reported in the Addendum 

should reflect the relevant tax 

reductions resulting from the Tax Cuts 

and Jobs Act.78 We encourage any passthrough entity reporting an income tax 

allowance in an Addendum to FERC 

Form No. 501–G to support its 

calculation of that income tax 

allowance, including showing where 

and how the income tax liability is 

incurred.79 Some commenters argue that 

pass-through entities have complex 

ownership forms which may be relevant 

to assessing whether there is a double 

recovery of tax costs when affording any 

such entity an income tax allowance in 

addition to a DCF ROE.80 Although not 

required, in preparing any Addendum 

to FERC Form No. 501–G, we encourage 

pass-through entities to provide any 

information regarding their particular 

circumstances or ownership structures 

that they consider relevant in assessing 

any potential United Airlines doublerecovery issue. 

61. We emphasize that this one-time 

filing of FERC Form No. 501–G and the 

Addendum are for informational 

purposes pursuant to NGA sections 10 

and 14. As discussed below, we also 

emphasize that in any subsequent NGA 

section 5 proceeding initiated by the 

Commission (regardless of the contents 


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81 Interstate Natural Gas Ass’n of America v. 

FERC, 285 F.3d 18, 38 (2002) (INGAA) (observed 

that the Commission would ‘‘shoulder the burden 

under [section] 5 of the NGA’’ with respect to any 

rate change and found ‘‘no violation of the NGA’’ 

with respect to ‘‘the Commission’s determination to 

extract information from pipelines relevant to the 

practical issues’’). 

82See Tuscarora Gas Transmission Co., 154 FERC 

¶ 61,273, at PP 4–14 (2016) (requiring a pipeline to 

submit a more detailed cost and revenue study than 

that which the Commission is proposing here). 

83The Commission proposed to exempt from this 

requirement (1) interstate natural gas pipelines 

whose rates are being examined in a general NGA 

section 4 rate case or an NGA section 5 

investigation and (2) pipelines that file a prepackaged uncontested rate settlement before the 

deadline for their One-time Report. 

84FERC Form Nos. 2s (Annual report for Major 

natural gas companies) and 2–As (Annual report 

for Nonmajor natural gas companies) for calendar 

year 2017 were due April 18, 2018. 18 CFR 

260.1(b)(2) & 260.2(b)(2). 

85Enable Interstate Pipelines Comments at 13–17; 

Southern Star Comments at 3–5; TransCanada 

Comments at 4–7. 

86Consumers Energy Co. v. FERC, 226 F.3d 777 

(6th Cir. 2000) (Consumers). 

87Enable Interstate Pipelines Comments at 14. 

88Enable Interstate Pipelines Comments at 15. 

89Southern Star Comments at 3–4. 

90 General Motors Corp v. FERC, 613 F.2d 939, 

944 (D.C. Cir. 1979); Southern Union Gas Co., 840 

F.2d 964, 968 (D.C. Cir. 1988); see also Iroquois Gas 

Transmission System, L.P., 69 FERC ¶ 61,165, at 

61,631 (1994); JMC Power Projects v. Tennessee Gas 

Pipeline, Co., 69 FERC ¶ 61,162 (1994), reh’g 

of the FERC Form No. 501–G or the 

optional Addendum), the Commission 

will have the burden under NGA section 

5 to justify any changes to the pipeline’s 

rates.81

c. Other Issues 

62. In response to the comments, we 

decline to clarify further our income tax 

allowance policies for MLP pipelines or 

other pass-through entities. As modified 

above, the rule does not require passthrough entities to eliminate the income 

tax allowance in limited section 4 

filings pursuant to § 154.404 or in any 

subsequent rate proceeding. As for the 

commenters’ request to clarify whether 

pass-through entities will be granted an 

income tax allowance in future rate 

proceedings, the Commission will not 

speculate now on future potential 

actions. We recognize that the Revised 

Policy Statement itself is guidance, not 

binding precedent, but any participant 

in a subsequent rate proceeding must be 

prepared to address the Opinion No. 

511–C and United Airlines precedent. 

Moreover, this binding precedent, as 

well as the Commission’s Revised 

Policy Statement, will be considered in 

any subsequent section 5 action, 

whether initiated by the Commission or 

by any shipper. 

B. One-time Report 

63. In the NOPR, the Commission 

proposed to exercise its authority under 

NGA sections 10(a) and 14(a) 82 to 

require all interstate natural gas 

pipelines that file a 2017 FERC Form 

No. 2 or 2–A to submit an abbreviated 

cost and revenue study in a format 

similar to the cost and revenue studies 

the Commission has attached to its 

orders initiating NGA section 5 rate 

investigations in recent years.83 Using 

the data in the pipelines’ 2017 FERC 

Form Nos. 2 and 2–A, these studies 

would estimate (1) the percentage 

reduction in the pipeline’s cost of 

service resulting from the Tax Cuts and 

Jobs Act and the Revised Policy 

Statement, and (2) the pipeline’s current 

ROEs before and after the reduction in 

corporate income taxes and the 

elimination of income tax allowances 

for MLP pipelines. The proposed Onetime Report is an Excel spreadsheet 

with formulas. 

64. The Commission stated that the 

Commission and interested parties 

could use this information in the Onetime Report in considering whether to 

initiate NGA section 5 rate 

investigations of pipelines which do not 

opt to file a limited NGA section 4 to 

reduce their rates or commit to make a 

general NGA section 4 filing by 

December 31, 2018, and the order in 

which to initiate any such investigations 

so as to make the most efficient use of 

the Commission’s and interested parties’ 

resources to provide consumer benefits. 

65. The cost and revenue study 

required by the One-time Report 

incorporates all the major cost 

components of a jurisdictional cost of 

service, including: Administrative and 

General, Operation and Maintenance, 

other taxes, depreciation and 

amortization expense, and the return 

related components of ROE, interest 

expenses and income taxes. Most of the 

required data is to be taken directly 

from the respondent’s 2017 FERC Form 

No. 2 or 2–A 84 without modification. 

However, the NOPR stated that, if a 

pipeline believes that this data does not 

reflect its current situation, the pipeline 

may make adjustments to individual 

line items in additional work sheets, 

referred to below as an Addendum to 

the FERC Form No. 501–G. The NOPR 

stated that all adjustments should be 

shown in a manner similar to that 

required for adjustments to base period 

numbers provided in statements and 

schedules required by sections 154.312 

and 154.313 of the Commission’s 

regulations. 

66. The NOPR also proposed an 

Implementation Guide for One-time 

Report on Rate Effect of the Tax Cuts 

and Jobs Act (Implementation Guide), 

providing additional guidance to parties 

as to the expected data entries, 

including the proposed staggered 

compliance dates and the list of 

companies for each of the four 

compliance periods. 

1. Legal Authority 

a. Comments 

67. Southern Star, TransCanada, and 

Enable Interstate Pipelines question the 

Commission’s legal authority to require 

the One-time Report.85 They each raise 

the same argument: compelling a 

pipeline to file the One-time Report is 

equivalent to compelling the pipeline to 

initiate an NGA section 4 rate 

proceeding, which the Consumers court 

case prohibits.86 Enable Interstate 

Pipelines note that the ‘‘pipeline filing 

the form is not making a proposal to 

change rates under NGA Section 4, 

justify its rates, or take any position 

regarding its current or future rates.’’ 87

Enable Interstate Pipelines argue that 

because the Commission has ‘‘stated 

that it will ‘consider whether to initiate 

an investigation under NGA Section 5 

based upon the ‘statement filed with the 

form,’’’ and because intervenors can 

‘‘make any further comments that 

intervenors want,’’ the effect is to 

‘‘require[] pipelines to justify their 

current rates through statements.’’ 88

68. Southern Star contends that, by 

permitting pipelines to make 

adjustments to individual line items in 

the FERC Form No. 501–G on additional 

worksheets and support those 

adjustments in a separate document, the 

Commission is requiring pipelines to 

justify their existing rates under the 

guise of an informational filing. 

Southern Star states that making any 

such adjustments based on more recent 

data would require the pipeline to make 

judgement calls with respect to data 

sources and reliability of the type it 

makes in an NGA section 4 rate filing.89

b. Discussion 

69. These comments misapprehend 

both the nature of the One-time Report 

and the holding in Consumers. The 

primary purpose of the One-time 

Report, together with any comments and 

protests to it, is to provide information 

relevant to determining whether the 

Commission should exercise its 

discretion to initiate an investigation 

under NGA section 5 as to whether the 

subject interstate natural gas pipeline 

may be collecting unjust and 

unreasonable rates in light of the recent 

reduction in the corporate income tax 

rate and change in the Commission’s 

income tax allowance policies.90


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denied, 70 FERC ¶ 61,168, at 61,528 (1995), 

affirmed, Ocean States Power v. FERC, 84 F.3d 1453 

(D.C. Cir. 1996) (unpublished opinion). 

91See, e.g., Natural Gas Pipeline Co. of America 

LLC, 158 FERC ¶ 61,044 at P 1; Wyoming Interstate 

Co., L.L.C., 158 FERC ¶ 61,040 at P 1; Tuscarora Gas 

Transmission Co., 154 FERC ¶ 61,030 at P 1, reh’g 

denied, 154 FERC ¶ 61,273. 

92Consumers, 226 F.3d at 777 (‘‘Should FERC 

wish [the pipeline] to make periodic informational 

filings, it may of course so require pursuant to 

[section] 10a of the NGA.’’). 

93 Id. at 781. 

94See, e.g., Hattiesburg Industrial Gas Sales, 

L.L.C., 134 FERC ¶ 61,236 at P 13 (imposing a fiveyear rate review requirement on Hattiesburg 

Industrial Gas Sales, L.L.C.). 

95Narragansett Electric Co., 155 FERC ¶ 61,159, 

at P 2 & n.15 (2016). 

96 Id. 

97An interstate pipeline may also file a general 

NGA section 4 rate case. However, such a filing 

would not use the information in the One-time 

Report. Rather, a pipeline submitting a general 

section 4 rate case would be required to submit the 

statements and schedules set forth in 18 CFR 

154.312 or 313. 

98 866 F.2d 487 (D.C. Cir. 1989). 

99See Southern Star Comments at 7. 

100 18 CFR 284.7(d) (2011). 

101 INGAA, 285 F.3d at 38. 

70. The Commission routinely 

initiates NGA section 5 investigations 

‘‘based upon our review of publicly 

available information on file with the 

Commission.’’ 91 The court in 

Consumers did not prohibit such 

information collection; to the contrary, 

it condoned information collection.92

The limitation that Consumers placed is 

that the Commission must act ‘‘with 

clarity and precision’’ so as to ensure 

that any directive for the pipeline to 

make ‘‘informational filings’’ is just that, 

and not an NGA section 4 filing to 

‘‘justify its current rate.’’ 93

71. Indeed, this Final Rule is 

patterned on the Commission’s 

successful method of collecting 

information from the Hinshaw pipelines 

that were specifically at issue in 

Consumers. For the past decade, instead 

of requiring Hinshaw pipelines to 

periodically file to justify their current 

rates, the Commission now requires 

Hinshaw pipelines to periodically ‘‘file 

with the Commission an informational 

filing with cost, throughput, revenue 

and other data, in the form specified in 

§ 154.313 of the Commission’s 

regulations.’’ 94 These five-year review 

filings are docketed and noticed, and 

parties may intervene, comment, and 

protest.95 The Commission expressly 

warns Hinshaw pipelines that the 

Commission will use that informational 

filing ‘‘to determine whether any change 

in [the pipeline’s] interstate 

transportation or storage rates should be 

ordered pursuant to section 5 of the 

Natural Gas Act.’’ 96 This two-step 

process allows the Commission to 

collect cost-of-service data consistent 

with NGA section 10(a), which the 

Commission may rely upon in deciding 

whether to exercise its discretion to 

initiate an investigation of the Hinshaw 

pipeline’s rates pursuant to NGA section 

5. The Hinshaw pipeline is free, if it so 

chooses, to propose to modify its rates 

under NGA section 4, based on the cost 

and revenue information in the study 

submitted to the Commission. Absent 

such a voluntary section 4 filing, no 

change in the Hinshaw pipeline’s rates 

will occur, without the Commission 

satisfying its burden of persuasion 

under NGA section 5. 

72. The One-time Report, adopted in 

this Final Rule, will operate in a similar 

fashion. The Final Rule permits an 

interstate natural gas pipeline, if it so 

chooses, to submit a limited NGA 

section 4 filing reducing its rates to 

reflect the income tax reductions in the 

Tax Cuts and Jobs Act or following the 

United Airlines Issuances, using the 

information in the One-time Report.97

However, the Final Rule contains no 

requirement that an interstate pipeline 

make any form of rate filing. Indeed, as 

discussed further below, the Final Rule 

expressly permits interstate pipelines to 

take no action other than submitting the 

required One-time Report in order to 

avoid any implication that the 

Commission is requiring interstate 

pipelines to make an NGA section 4 rate 

change filing, contrary to the decision of 

the United States Court of Appeals for 

the D.C. Circuit in Public Service 

Commission of New York v. FERC98 that 

the Commission may not require 

pipelines to file rate cases under NGA 

section 4. 

73. The Commission rejects Southern 

Star’s contention that the Commission is 

requiring pipelines to justify their 

existing rates under the guise of an 

informational filing by permitting 

pipelines to make adjustments to 

individual line items in the FERC Form 

No. 501–G on additional worksheets. 

The FERC Form No. 501–G requires 

interstate natural gas pipelines to 

develop a cost and revenue study in 

which most of the data is taken directly 

from the pipeline’s FERC Form No. 2 or 

2–A without modification. Using 

formulas that are incorporated into the 

form that may not be changed by the 

pipeline, the FERC Form No. 501–G 

produces a cost and revenue study in a 

format similar to the cost and revenue 

studies the Commission has used in 

recent years to determine whether to 

initiate NGA section 5 rate 

investigations of individual pipelines. 

As Southern Star and other pipelines 

recognize, pipelines have little 

discretion in how they fill out the FERC 

Form No. 501–G.99 However, the 

Commission recognizes that the 2017 

calendar year data reported in the 

pipeline’s FERC Form No. 2 or 2–A may 

not be fully representative of the 

pipeline’s current situation when it files 

the FERC Form No. 501–G in the fall of 

2018. For example, shippers may have 

left the system after their contracts 

expired, the pipeline may have been 

unsuccessful in remarketing its 

capacity, or the pipeline may have 

restructured. Accordingly, the 

Commission is providing pipelines the 

opportunity to inform both it and other 

parties of significant changes in their 

situation by filing an Addendum to the 

FERC Form No. 501–G. The filing of 

such an Addendum is purely voluntary, 

but the information in such an 

Addendum should assist the 

Commission in determining what 

further steps to take with respect to the 

pipeline in question. 

74. The Commission recognizes that 

deciding what information, if any, to 

include in an Addendum to the FERC 

Form No. 501–G may require the 

pipeline to exercise some degree of 

judgment. However, that fact does not 

require the pipeline to make the 

equivalent of an NGA section 4 rate 

filing or improperly shift to the pipeline 

the burden of justifying its existing rates 

in violation of NGA section 5. In 

INGAA, the D.C. Circuit rejected a 

contention similar to the one made here 

by Southern Star. The Commission in 

Order No. 637 had directed each 

pipeline to file pro forma tariff sheets 

showing how it intended to comply 

with a regulation requiring pipelines to 

permit segmentation 100 or to explain 

why its system’s configuration justified 

curtailing segmentation rights. As in 

this rulemaking proceeding, the 

pipelines in the Order No. 637 

proceeding contended that requiring 

them to submit these filings 

impermissibly shifted the burden of 

proof, and the Commission had in 

essence required pipelines to make NGA 

section 4 filings to defend their current 

rates. The court rejected this argument, 

finding that the Commission had stated 

that it ‘‘will indeed shoulder the burden 

under [section] 5 of the NGA.’’ 101 As 

pertinent here, the court expressly 

stated that: 

As to the Commission’s determination to 

extract information from pipelines relevant to 

the practical issues, we see no violation of 

the NGA. The Commission has authority 

under [section] 5 to order hearings to 

determine whether a given pipeline is in 

compliance with FERC’s rules, 15 U.S.C. [ ] 

717d(a), and under [section] 10 and [section] 


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102 Id. (emphasis added). 

103See, e.g., Columbia Gas Transmission Corp., 

100 FERC ¶ 61,084, at PP 12–14 (2002), in which 

the pipeline described how its segmentation 

proposal complied with Order No. 637 in light of 

the operational characteristics of its system. 

104EQT Midstream Comments at 20; Spectra 

Comments at 11–12; Tallgrass Pipelines Comments 

at 23–24; TransCanada Comments at 16. 

105Spectra Comments at 12. 

106See NOPR, FERC Stats. & Regs. ¶ 32,725 at PP 

43–44. 

107 Id. P 29. 

108 Id. P 64. 

14 to require pipelines to submit needed 

information for making its [section] 5 

decisions, 15 U.S.C. [ ] 717i & 717m(c).102

75. The Commission’s decision in this 

Final Rule to authorize pipelines to 

submit an Addendum with their FERC 

Form No. 501–G fits even more easily 

with our NGA sections 10 and 14 

information collection authority than 

Order No. 637’s directive, affirmed in 

INGAA, that pipelines file pro forma 

tariff sheets showing how they intended 

to comply with the new segmentation 

regulation or explain why they should 

be exempted from that requirement. A 

pipeline’s filing of an Addendum to the 

FERC Form No. 501–G is voluntary, 

unlike Order No. 637’s mandatory 

requirement for each pipeline to state in 

its compliance proceeding how it 

believed shippers on its system should 

be permitted to segment their capacity 

in light of the operational requirements 

of their systems and to propose specific 

tariff language implementing the 

pipeline’s proposed segmentation 

plan.103

76. Moreover, in this Final Rule, 

unlike in Order No. 637, we have not 

yet initiated any investigation of a 

pipeline’s rates under NGA section 5. 

The Commission will review each 

pipeline’s FERC Form No. 501–G and 

Addendum not to set rates (absent a 

voluntary limited NGA section 4 filing), 

but to determine whether to exercise our 

discretion to initiate a rate investigation 

under NGA section 5. If we decide 

based on the information in the Onetime Report to initiate a section 5 

investigation, we will, as in the Order 

No. 637 compliance filings addressed in 

INGAA, ‘‘shoulder the burden under 

[section] 5 of the NGA.’’ We discuss 

further details of the procedures to be 

used in addressing the pipeline Onetime Reports below. 

2. Burden of Proof 

a. Comments 

77. Several commenters request 

confirmation that filing the FERC Form 

No. 501–G will not affect the burden of 

proof in future NGA section 4 or 5 rate 

proceedings, be used as evidence 

against or a concession by the pipeline, 

limit the pipeline’s ability to take 

contrary positions in the future, or 

otherwise constitute estoppel.104

Commenters note that the Commission 

is collecting this information under its 

NGA sections 10 and 14 authority, not 

its NGA section 4 or 5 authority. 

Commenters also argue that, because the 

FERC Form No. 501–G ‘‘hard-wires’’ 

certain components of a pipeline’s 

actual cost of service, such information 

would be inaccurate if used in a general 

ratemaking proceeding.105

b. Discussion 

78. We clarify that statements in a 

FERC Form No. 501–G will constitute a 

valid form of evidence, as noted below, 

but will not otherwise bind or estop a 

pipeline in future proceedings. Most 

obviously, if a pipeline elects Option 1, 

the special limited NGA section 4 rate 

proceeding based upon the FERC Form 

No. 501–G, the One-time Report, 

including any adjustments the pipeline 

proposes, will constitute a major part of 

its case in chief.106 We also clarify that 

the FERC Form No. 501–G can be used 

as evidence to the exact same extent that 

any other Commission form can be used 

as evidence. A pipeline will be 

responsible for the truthfulness of 

statements it makes in the One-time 

Report, but those statements must be 

evaluated in context, representing a 

necessarily incomplete picture of the 

company, under the constraints that are 

inherent in any one-size-fits-all form. 

79. Although the Commission and 

other stakeholders will use information 

in the FERC Form No. 501–G, together 

with any other information provided by 

the pipelines and commenters, in 

deciding whether to initiate a section 5 

proceeding to further investigate the 

justness and reasonableness of the 

pipeline’s rates, the Commission or 

complainant will still bear the burden of 

proof in section 5 proceedings. 

Furthermore, the pipeline will be free to 

argue that the information it provided in 

the FERC Form No. 501–G is 

unrepresentative of its true cost of 

service; those statements will not 

otherwise limit or estop the pipeline in 

future proceedings. 

3. Docketing and Comments 

80. The Commission proposed to 

assign each pipeline’s FERC Form No. 

501–G filing an RP docket number and 

to notice the filing providing for 

interventions and protests. Based on the 

information in that form, together with 

any statement filed with the form and 

comments by intervenors, the 

Commission stated that it will consider 

whether to initiate an investigation 

under NGA section 5 of those pipelines 

that have not filed a limited NGA 

section 4 rate reduction filing or 

committed to file a general NGA section 

4 rate case.107 The Commission also 

stated that, if the pipeline makes a 

limited NGA section 4 filing to reduce 

its rates to reflect the reduced income 

taxes in the Tax Cuts and Jobs Act, the 

Commission would assign the limited 

section 4 filing a separate docket 

number.108

a. Comments 

81. INGAA, Boardwalk, Williams, 

Spectra, Southern Star, and EQT 

Midstream argue that the Commission 

should eliminate the NOPR’s proposal 

to assign each pipeline’s FERC Form No. 

501–G filing an RP docket number. The 

Commission, they continue, does not 

assign docket numbers to FERC Form 

No. 2 and other similar informational 

filings, nor does it subject these filings 

to intervention and protest. They further 

argue that the NOPR provides no basis 

for modifying this practice solely for the 

FERC Form No. 501–G reports, and 

there is no statutory authorization for 

treating a FERC Form No. 501–G 

submission as a rate filing pursuant to 

NGA sections 4 or 5. 

82. These commenters also object to 

the Commission’s proposal to formally 

notice and permit shippers to intervene 

and protest the filings. Boardwalk 

believes that the NOPR offered no basis 

for allowing protests to FERC Form No. 

501–G filings. INGAA, Boardwalk, and 

Spectra state that this proposal ignores 

that the submission of FERC Form No. 

501–G is not a voluntary rate filing by 

the pipeline subject to the Commission’s 

approval pursuant to NGA section 4, nor 

is the FERC Form No. 501–G submission 

a response to Commission action under 

NGA section 5. They argue that the 

NOPR’s proposal to allow protests to the 

FERC Form No. 501–G risks upsetting 

these fundamental requirements of the 

NGA, because the NOPR appears to 

contemplate that the dockets created for 

the informational FERC Form No. 501– 

G submission could be turned into rate 

proceedings without meeting the 

statutory standards of NGA sections 4 or 

5. Thus, INGAA and Southern Star 

continue, pipelines will necessarily 

respond to any protest, converting an 

informational filing into a de facto rate 

filing. Southern Star concludes by 

stating that the Commission should treat 

the FERC Form No. 501–G filing similar 

to a FERC Form No. 2 filing and not 

permit intervention and comments. 

83. These parties also assert that the 

proposal to allow interventions and 


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109The Commission established eTariff Type of 

Filing Code (ToFC) 1430 for FERC Form No. 501– 

G filings. 

110Such broad grants of authority have been held 

‘‘not restricted to procedural minutiae, and [to] . . . 

authorize means of regulation not spelled out in 

detail, provided the agency’s action conforms with 

the purposes and policies of Congress and does not 

contravene any terms of the Act.’’ Mesa Petroleum 

Co. v. F.P.C., 441 F.2d 182, 187 (5th Cir. 1971) 

(citing Niagara Mohawk Power Corp. v. F.P.C., 379 

F.2d 158). See also Public Service Comm’n of State 

of N.Y. v. F.P.C., 327 F.2d 893, 897 (D.C. Cir. 1964). 

(NGA Section 16 provides a basis for the 

Commission to cope with unforeseen problems, and 

is not confined to procedural regulations, but is a 

broad grant of authority). 

111See cases cited supra note 22. 

112See NOPR, FERC Stats. & Regs. ¶ 32,725 at P 

64 (establishing an eTariff ToFC 1440 for the 

limited NGA section 4 filings, separate from the 

ToFC for the FERC Form No. 501–G filings). These 

different filing codes will produce separate root 

docket numbers for the two types of filing. 

protests of FERC Form No. 501–G filings 

is unnecessary and duplicative. INGAA, 

Boardwalk, and EQT Midstream argue 

that shippers can use FERC Form No. 

501–G as a tool to assist their 

determination of whether to initiate 

NGA section 5 rate cases requesting 

reductions in pipelines’ rates, in a 

separate proceeding. INGAA and 

Spectra also speculate that the 

Commission may be inviting duplicative 

and confusing efforts if pipelines 

subsequently file an actual rate 

proceeding. Similarly, Williams urges 

the Commission to not allow 

interventions and protests to the 

pipeline’s filing of the report itself. 

Williams argues that foreclosing 

comments to the FERC Form No. 501– 

G would not leave shippers without a 

forum for stating their views on a 

pipeline’s FERC Form No. 501–G filings. 

b. Discussion 

84. The Commission adopts the NOPR 

proposal to require pipelines to file 

FERC Form No. 501–G through 

eTariff,109 assign each filing a separate 

RP root docket number, and notice the 

filing for interventions, comments, and 

protests. This method of processing the 

FERC Form No. 501–G does not convert 

the form into an NGA section 4 filing, 

nor do the results of FERC Form No. 

501–G constitute a finding that the 

filer’s rates are no longer just and 

reasonable or establish new just and 

reasonable rates pursuant to NGA 

section 5. 

85. Contrary to some commenters’ 

concerns, there is no NGA-required 

relationship between the assignment of 

a particular docket prefix and a 

particular provision of the statute. 

Docketing is a Commission 

administrative tool used to control 

workflow. Under NGA section 16, the 

Commission has the general statutory 

authority ‘‘to perform any and all acts, 

and to prescribe, issue, make, amend 

and rescind such orders, rules and 

regulations as it may find necessary or 

appropriate to carry out the provisions 

of this act.’’ 110 Docketing FERC Form 

No. 501–G filings is an administrative 

function which creates no presumption 

that the filing is pursuant to NGA 

sections 4 or 5. 

86. The commenters also argue that 

the proposed notice and opportunity for 

others to comment on the FERC Form 

No. 501–G filings is without precedent, 

and converts the filing of a financial 

report into a de facto NGA section 4 or 

5 proceeding. 

87. The proposed FERC Form No. 

501–G, together with any comments and 

protests, is intended to assist the 

Commission in determining whether to 

initiate an investigation under NGA 

section 5 as to whether the subject 

jurisdictional natural gas pipeline may 

be collecting unjust and unreasonable 

rates in light of the recent reduction in 

the corporate income tax rate and 

change in the Commission’s income tax 

allowance policies. Thus, the filing of 

the FERC Form No. 501–G does not 

itself initiate an NGA section 5 

investigation, but rather gives all parties 

an opportunity to advise the 

Commission on whether it should 

initiate such an investigation. 

88. The pipeline’s filing of the FERC 

Form No. 501–G, together with any 

Addendum proposing adjustments to 

reflect updated information, gives the 

pipeline an opportunity to explain why 

no further investigation is needed. 

Noticing the pipeline’s filing for 

comment and protest allows other 

interested parties to state their views as 

to whether an investigation is needed. 

As the commenters have noted, the 

Commission cannot simply require a 

pipeline to reduce its rates consistent 

with a known reduction in a single cost 

component of a cost-based rate. The 

Commission must look at other factors, 

including whether the pipeline is over 

recovering its overall cost of service and 

the applicability of any settlement rate 

moratorium. These other factors are not 

limited to those of interest to pipelines. 

Shippers and customers pay these costbased rates and, for some pipelines, are 

parties to rate settlements. These parties 

also have an interest in whether the 

currently effective rates are no longer 

just and reasonable. The Commission 

believes allowing the parties to file 

comments will create a more complete 

record. That record will permit the 

Commission to better evaluate the 

pipelines’ FERC Form No. 501–G filings 

and any additional statements or 

material that pipelines may file in 

determining whether to exercise its 

discretion to initiate an investigation of 

the pipeline’s rates under NGA section 

5. 

89. If the Commission does decide to 

initiate an NGA section 5 investigation, 

it will issue an order establishing a 

proceeding for that purpose, similar to 

prior orders establishing NGA section 5 

investigations of natural gas pipeline 

rates.111 Thus, the Commission will 

require the pipeline to submit a cost and 

revenue study based on cost and 

revenue information for the latest 12- 

month period available. That cost and 

revenue study, not the FERC Form No. 

501–G based on 2017 FERC Form No. 2 

or 2–A data, will provide the 

evidentiary starting point for the actual 

NGA section 5 rate investigation. In 

short, the FERC Form No. 501–G, 

together with comments and protests 

thereto, will assist the Commission in 

evaluating whether to initiate a section 

5 investigation, but will not be the 

record basis for any actual order 

requiring the pipeline to modify its rates 

pursuant to NGA section 5. A 

subsequent hearing ordered by the 

Commission will be necessary to 

develop the record on which any NGA 

section 5 action would be taken. The 

Commission agrees with the parties that 

such determinations must be performed 

on a pipeline-by-pipeline basis. 

90. The second purpose of the FERC 

Form No. 501–G, together with any 

adjustments the pipeline may propose, 

is to serve as the evidentiary support for 

any limited NGA section 4 filing the 

pipeline may propose pursuant to this 

rule to reduce its rates to reflect the 

reduced income taxes under the Tax 

Cuts and Jobs Act and/or the United 

Airlines Issuances. As proposed by the 

NOPR, the Commission will assign a 

separate docket number to any such 

limited NGA section 4 filing,112 and 

thus the limited NGA section 4 filing, 

and any protests thereto, will be 

considered in a separate proceeding 

from the docket established for the 

FERC Form No. 501–G itself. 

91. Therefore, the proposed process 

adopted here, contrary to the concerns 

of these commenters, is not a 

requirement for the pipelines to file an 

NGA section 4 rate case, nor are the 

results from FERC Form No. 501–G a 

finding that the current rate is not just 

and reasonable or the specification of a 

new just and reasonable rate pursuant to 

NGA section 5. However, the process 

the Commission is adopting is intended 

to help identify which pipelines deserve 

closer attention. 

92. Some commenters believe that 

permitting parties to comment on 


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113NOPR, FERC Stats. & Regs. ¶ 32,725 at P 29. 

114LDC Coalition Comments at 12. 

115 18 CFR part 385. 

116 18 CFR 385.201. 

117 18 CFR 385.210. 

118 18 CFR 385.214. 

119 18 CFR 385.211. 

120See 18 CFR 375.307(b)(3)(ii) (delegating to the 

Office of Energy Market Regulation the authority to 

‘‘Issue and sign requests for additional information 

regarding applications, filings, reports and data 

processed by the Office of Energy Market 

Regulation.’’). 

121 15 U.S.C. 717t. 

122See, e.g., Southern Natural Gas Co. L.L.C., 139 

FERC ¶ 61,237, at P 154 (2012); Alliance Pipeline 

L.P., 140 FERC ¶ 61,212, at P 20 (2012); Northern 

Natural Gas Co., 119 FERC ¶ 61,035, at P 37 (2007). 

123El Paso Natural Gas Co., Opinion No. 528, 145 

FERC ¶ 61,040, at P 642 (2013), reh’g denied, 

pipelines’ FERC Form No. 501–G 

reports may be duplicative. 

Notwithstanding this possibility, we 

believe there is value in providing 

interested parties an opportunity to 

comment on a pipeline’s FERC Form 

No. 501–G report, even if they might 

raise similar arguments later, should the 

Commission decide to initiate 

additional proceedings. 

4. Rights of Intervenors 

93. In the NOPR, the Commission 

stated: 

The Commission will assign each 

pipeline’s filing of the FERC Form No. 501– 

G an RP docket number and notice the filing 

providing for interventions and protests. 

Based on the information in that form, 

together with any statement filed with the 

form and comments by intervenors, the 

Commission will consider whether to initiate 

an investigation under NGA section 5 of 

those pipelines that have not filed a limited 

NGA section 4 rate reduction filing or 

committed to file a general NGA section 4 

rate case.113

a. Comments 

94. In addition to the comments 

discussed above, LDC Coalition raises 

several questions about the role of 

parties intervening in One-time Report 

dockets. In particular, in the event that 

a party has questions or concerns about 

a given One-time Report, LDC Coalition 

asks: 

Will Commission Staff have access to the 

deficiency notice process? 

Does the Commission contemplate setting 

One-time Report proceedings for technical 

conference, hearing, and/or settlement judge 

proceedings? 

Will parties have the ability to seek 

discovery from the pipeline on its FERC 

Form No. 501–G inputs and calculations 

even before the Commission sets a One-time 

Report for technical conference, hearing, or 

settlement judge procedures? 

Will the Commission issue an Order in 

response to each FERC Form No. 501–G filing 

either closing out the proceeding or 

continuing the review in that or another 

docket? 

If the Commission intends to issue an order 

in each docket, will it state an expected 

timeline for doing so to provide customers 

certainty about the process? 

What actions will the Commission take if 

a pipeline does not submit an NGA section 

4 filing or pre-filing settlement by the 

proposed deadline of December 31, 2018? 

What options do the Commission and 

pipeline customers have if a pipeline fails to 

timely submit a FERC Form No. 501–G or 

does not strictly follow Commission 

guidance in completing a submitted form? 114

b. Discussion 

95. We clarify that Subpart B of the 

Commission’s Rules of Practice and 

Procedure 115 does not apply to the 

various reports required by Part 260 of 

the Commission’s regulations. Rule 201 

provides that Subpart B of the Rules of 

Practice and Procedure apply ‘‘to any 

pleading, tariff or rate filing, notice of 

tariff or rate examination, order to show 

cause, intervention, or summary 

disposition;’’ 116 Part 260 reports fall 

into none of those categories. Therefore, 

the Commission clarifies the procedures 

to be used in noticing pipelines’ filings 

of the FERC Form No. 501–G for 

intervention, protest, and comment, as 

well as addressing LDC Coalition’s other 

procedural questions. 

96. First, the Commission is revising 

the Implementation Guide for the FERC 

Form No. 501–G to provide that the 

Secretary will issue a notice of each 

pipeline’s filing of its FERC Form No. 

501–G, consistent with § 385.210 of the 

Commission’s Rules of Practice and 

Procedure.117 Unless the notice 

provides otherwise, interventions, 

protests, and comments will be due not 

later than 12 days after the filing of the 

subject FERC Form No. 501–G. This will 

mean that such interventions, protests, 

and comments will be due on the same 

day as interventions, protests, and 

comments are due on any limited NGA 

section 4 filing accompanying the FERC 

Form No. 501–G, as provided by 

§ 154.210 of the Commission’s Rules of 

Practice and Procedure. As revised, the 

Implementation Guide also states that 

interventions will be governed by 

§ 385.214 of the Commission’s Rules of 

Practice and Procedure,118 and protests 

will be governed by § 385.211.119

97. Proceeding to LDC Coalition’s list 

of questions, we clarify that 

Commission staff may issue data 

requests to pipelines if it identifies 

problems with their FERC Form No. 

501–G.120 However, the Commission 

will not set One-time Report 

proceedings for technical conference, 

hearing, and/or settlement judge 

proceedings, nor will it allow discovery; 

such actions would only be appropriate 

in the context of an NGA section 4 or 

5 rate proceeding. The purpose of 

publicly docketing the One-time Reports 

is not to conduct a rate proceeding, but 

rather to allow for public discussion of 

whether the Commission should 

exercise its discretion to initiate an NGA 

section 5 investigation of the subject 

pipeline’s existing rates because of the 

Tax Cuts and Jobs Act’s reduction in 

income taxes or the United Airlines 

Issuances. 

98. If the Commission decides to 

initiate a section 5 investigation, it will, 

as described above, issue an order 

establishing a hearing under NGA 

section 5. If the Commission determines 

that the information in a pipeline’s 

FERC Form No. 501–G does not justify 

initiating such an NGA section 5 

proceeding, the Commission will issue 

a notice accepting the pipeline’s Onetime Report. That notice shall close the 

One-time Report proceeding. But the act 

of acceptance shall only constitute 

assurance that the Commission accepts 

the report, and does not constitute a 

statement or action on the pipeline’s 

rates, nor does it foreclose the 

Commission from initiating a future 

NGA section 5 investigation based upon 

new information such as the pipeline’s 

future FERC Form No. 2 or 2–A reports 

or for other reasons. The Commission 

will not establish a formal deadline for 

acting on each One-time Report, but will 

act as promptly as possible on all filings 

in order to promote rate certainty for 

pipelines and customers. 

99. If a pipeline refuses to promptly 

submit a One-time Report, or to correct 

a patently erroneous or incomplete Onetime Report, the Commission could 

consider the pipeline to be in violation 

of its reporting obligation.121 Likewise, 

if a pipeline commits to submit an NGA 

section 4 filing or pre-filing settlement 

by the proposed deadline of December 

31, 2018, but fails to do so, the 

Commission could consider the pipeline 

to be in violation of its reporting 

obligation. 

5. Use of 10.55 Percent Indicative 

Return on Equity 

100. A cost and revenue study 

requires an indicative return on equity 

(ROE). In the proposed FERC Form No. 

501–G, the Commission used, consistent 

with Commission practice, the last 

litigated ROE applicable to situations 

involving existing plant.122 The last 

litigated ROE was in El Paso, wherein 

the Commission adopted a ROE of 10.55 

percent.123


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Opinion No. 528–A, 154 FERC ¶ 61,120 (2016) (El 

Paso). 

124 INGAA, Southern Star, Boardwalk, Dominion 

Energy, Williams, Tallgrass Pipelines, TransCanada, 

Enable Interstate Pipelines, Kinder Morgan, and 

Spectra. 

125NOPR, FERC Stats. & Regs. ¶ 32,725 at P 35 

(citing Transcontinental Gas Pipe Line Corp., 

Opinion No. 414–A, 84 FERC ¶ 61,084, at 61,413– 

61,415, reh’g denied, Opinion No. 414–B, 85 FERC 

¶ 61,323 (1998), petition for review denied sub nom. 

N.C. Utils. Comm’n v. FERC, D.C. Cir. Case No. 99– 

1037 (Feb. 7, 2000) (per curiam)). 

126 Id. P 35. 

a. Comments 

101. The Pipeline Commenters124

argue that use of an indicative ROE of 

10.55 percent in the FERC Form No. 

501–G is arbitrary and capricious. They 

note that the El Paso ROE is based on 

test period data that is now about seven 

years old, that the Commission has not 

shown that the financial data 

underlying that proceeding is currently 

representative for any pipeline, let alone 

for all pipelines, and the indicative ROE 

is artificially low. Further, they contend 

that El Paso is not final as it has not 

been reviewed by the Court of Appeals. 

Citing previous Commission NGA 

section 5 show cause proceedings, 

Kinder Morgan argues that the 

Commission has not previously required 

pipelines to propose a ROE. The 

Pipeline Commenters request that the 

Commission clarify that the 10.55 

percent ROE is to be used only for the 

purposes of completing FERC Form No. 

501–G, and is not an indicative ROE or 

reflective of the ROE that would be 

determined in a general rate case 

proceeding. Dominion Energy, Spectra 

and Tallgrass request that pipelines be 

permitted to use their own ROEs. 

102. Enable Interstate Pipelines argue 

that the Commission should permit 

ROEs derived during a rate proceeding 

or established pursuant to approved 

settlements that were used to set their 

current rates, or rely upon the 

methodology used to set such ROEs. 

Enable Interstate Pipelines also argue 

that if pass-through entities are not 

permitted to report an income tax 

allowance on the FERC Form No. 501– 

G, the Commission must increase the 

allowable ROE for such pipelines to 

allow them to report a higher ROE than 

corporate pipelines on the form. 

Alternatively, Enable Interstate 

Pipelines argue that the Commission 

should adjust the ROE upwards by 

eliminating the reduction in long-term 

growth rates for MLP pipelines. 

b. Discussion 

103. The Commission adopts the 

NOPR’s proposal to require that each 

pipeline’s FERC Form No. 501–G be 

completed using an indicative ROE of 

10.55 percent, consistent with the ROE 

determined in El Paso, the last rate case 

where that issue was fully litigated. The 

One-time Report is an informational 

filing required pursuant to NGA 

sections 10 and 14 that serves two 

purposes: (1) To help determine 

whether to initiate NGA section 5 

investigations of interstate natural gas 

pipelines’ rates and (2) to support any 

limited NGA section 4 filings pipelines 

may choose to make to reduce their 

rates to reflect the Tax Cuts and Jobs Act 

or the United Airlines Issuances. 

104. When used for the first purpose, 

the FERC Form No. 501–G is intended 

to provide a rough estimate of the 

pipeline’s return on equity before and 

after the Tax Cuts and Jobs Act or the 

United Airlines Issuances. The data in 

the FERC Form No. 501–G, including 

the indicative ROE, will not be used to 

actually establish rates in any NGA 

section 5 investigation that the 

Commission may initiate. Rather, any 

rates determined in an NGA section 5 

investigation, including ROE, will be 

based on the record developed in any 

hearing established by the Commission, 

and in such a hearing, the Commission 

will have the burden of persuasion 

under NGA section 5 on all issues, 

including ROE. 

105. In addition, although the 

Commission recognizes that the 10.55 

percent ROE determined in El Paso was 

based on financial data from 2011, no 

commenter has provided any updated 

ROE analysis using current financial 

data that the Commission could use in 

the FERC Form No. 501–G in place of 

the El Paso ROE. There is thus nothing 

in the comments to show that an 

updated ROE analysis would produce a 

significantly different ROE than that 

approved in El Paso. Instead, pipeline 

commenters request that they be 

permitted to use their own ROEs or 

ROEs derived in a rate proceeding or 

established pursuant to approved 

settlements. However, the last rate cases 

of many pipelines occurred as long ago 

as, or even before, the El Paso rate case. 

Moreover, many settlements are ‘‘black 

box’’ settlements that do not have a 

ROE. In these circumstances, the 

Commission finds that using the El Paso 

10.55 percent ROE as the indicative 

ROE in all pipelines’ FERC Form No. 

501–G is preferable to pipelines using a 

variety of ROEs, which they claim 

represent their currently approved 

ROEs, but which in almost all cases 

were not fully litigated, in contrast to 

the El Paso ROE, and may be as old or 

older than the 10.55 percent El Paso 

ROE. However, if a pipeline believes 

that the 10.55 percent El Paso ROE does 

not represent a reasonable ROE for its 

system in light of its current 

circumstances, the pipeline may file an 

alternative ROE, together with support 

for that ROE as described below, as part 

of its Addendum to the required FERC 

Form No. 501–G. 

106. The FERC Form No. 501–G does 

serve a ratemaking purpose in the 

narrow situation when it is used as 

support for the limited NGA section 4 

filing this Final Rule authorizes a 

pipeline to voluntarily make to reduce 

its rates to reflect the Tax Cuts and Jobs 

Act or the United Airlines Issuances. 

Our requirement that pipelines use the 

El Paso 10.55 percent ROE in filling out 

the FERC Form No. 501–G does not 

mean that they must use that ROE in a 

limited section 4 filing. As just 

described, the pipeline may submit an 

Addendum with its FERC Form No. 

501–G setting forth an alternative ROE 

and use that ROE in calculating its 

proposed percentage rate reduction in 

its limited NGA section 4 rate filing. 

When a pipeline proposes such an 

alternative ROE in a limited section 4 

rate filing, the Commission would 

expect the pipeline to provide full 

support for its proposed ROE, including 

a Discounted Cash Flow (DCF) analysis 

of a proxy group consistent with 

Commission policy. Such support is not 

necessary if the pipeline proposes to 

reduce its rates by a percentage 

calculated consistent with the FERC 

Form No. 501–G, without any 

Addendum. 

6. Use of Stated Capital Structure 

107. In the NOPR, the Commission 

stated that the established policy in rate 

cases is that a company may use its 

actual capital structure only if it ‘‘(1) 

issues its own debt without guarantees, 

(2) has its own bond rating, and (3) has 

a capital structure within the range of 

capital structures approved by the 

Commission.’’ 125 Where these 

requirements are not met, the 

Commission will use the consolidated 

capital structure of the parent company 

or a hypothetical capital structure. The 

NOPR proposed that the One-time 

Report would follow this policy: 

The proposed form requests the 

respondent’s FERC Form Nos. 2 or 2–A 

equity related balance sheet items. However, 

if that data does not satisfy the three-part test 

of Opinion No. 414, et al., the form provides 

alternative data entries to reflect parent or 

hypothetical capital structures consistent 

with Opinion No. 414, et al.126

108. If neither the pipeline’s own 

capital structure nor its parent’s capital 

structure satisfies the Commission’s 

policy, the proposed FERC Form No. 


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127Boardwalk Comments at 27–29; Enable 

Interstate Pipelines Comments at 22; INGAA 

Comments at 36–38; Kinder Morgan Comments at 

23–26. 

128Boardwalk Comments at 28; INGAA 

Comments at 36. 

129Boardwalk Comments at 29. 

130Enable Interstate Pipelines Comments at 24. 

131 Kinder Morgan Comments at 24. 

132 INGAA argues that, in order to use a different 

capital structure than that used in the FERC Form 

No. 2 or 2–A, ‘‘the Commission must first show that 

the pipeline’s submitted data is not just and 

reasonable.’’ INGAA Comments at 28. However, 

data cannot be just or unjust, which is why NGA 

section 10 instead speaks of ‘‘specific answers,’’ 

‘‘full information,’’ and ‘‘adequate provision.’’ The 

Commission is not modifying any rates pursuant to 

NGA section 5 in the FERC Form No. 501–G, but 

simply seeking to estimate the pipeline’s current 

return on equity for purposes of deciding whether 

to initiate a rate investigation pursuant to NGA 

section 5. 133Bear Creek Storage Co., L.L.C., 137 FERC 

¶ 61,134, at P 8 n.6 (2011). See also Dominion 

Energy Overthrust Pipeline, LLC, 162 FERC ¶ 

61,218, at Appendix, n.1 & 2 (2018); Midwestern 

Gas Transmission Co., 162 FERC ¶ 61,219, at 

Appendix, n.1 & 2 (2018); Natural Gas Pipeline Co. 

of America LLC, 158 FERC ¶ 61,044, at Appendix, 

n.1 & 2 (2017); Wyoming Interstate Co., L.L.C., 158 

FERC ¶ 61,040, at Appendix, n.1 & 2 (2017); 

Tuscarora Gas Transmission Co., 154 FERC ¶ 

61,030, at Appendix, n.1 & 2 (2016); MIGC LLC, 137 

FERC ¶ 61,135, at Appendix, n.3 (2011); ANR 

Storage Co., 137 FERC ¶ 61,136, at Appendix, n.2 

(2011). 

501–G requires use of a 50 percent 

equity, 50 percent debt capital structure, 

with an implied debt rate of five 

percent. 

a. Comments 

109. Several pipeline commenters 

argue that pipelines should be permitted 

to use their capital structure as reported 

on the FERC Form No. 2 or 2–A, even 

if that capital structure does not comply 

with the Opinion No. 414, et al., 

policy.127 Boardwalk and INGAA argue 

that using a hypothetical capital 

structure attempts to shift to the 

pipeline the burden of justifying its own 

capital structure.128 Boardwalk argues 

that requiring different data on the 

FERC Form No. 501–G than on the 

FERC Form No. 2 ‘‘impermissibly blurs 

the distinction between NGA sections 4 

and 5.’’ 129 They also argue that the 

hypothetical capital structure that FERC 

Form No. 501–G requires when neither 

the pipeline’s nor its parent’s capital 

structure satisfies Commission policy is 

financially unrealistic, and that 

companies that attempt to actually 

implement them would harm their 

credit rating and financial viability. 

Enable Interstate Pipelines argue that 

the NOPR proposes only three possible 

choices of capital structure, but that 

ratemaking precedent allows other 

possibilities, such as using an 

intermediate subsidiary’s structure. 

Enable Interstate Pipelines also argue 

that the FERC Form No. 501–G default 

50/50 debt/equity ratio is inconsistent 

with ratemaking precedent concerning 

hypothetical capital structures, which 

they state uses the average capitalization 

of a proxy group to develop a 

hypothetical capital structure.130

110. Kinder Morgan notes that page 4 

of the proposed FERC Form No. 501–G 

asks the respondent, ‘‘does the Capital 

Structure and the Long-Term Debt from 

the cited source meet the requirements 

of Opinion No. 414, et al.?’’ Kinder 

Morgan argues that this question 

impermissibly goes beyond a request for 

information, and instead would compel 

the respondent to provide a legal 

opinion. Kinder Morgan argues sections 

10(a) and 14(a) of the NGA do not 

permit the Commission to solicit legal 

positions of a pipeline rather than 

information.131 Kinder Morgan notes 

that the Commission has not asked this 

question or similar questions in its 

recent NGA section 5 show cause 

orders. Kinder Morgan argues that it is 

especially inconsistent to compel a 

respondent to take a legal position given 

that page 4 of the proposed FERC Form 

No. 501–G also compels certain 

respondents to report a hypothetical 50/ 

50 debt/equity capital structure rather 

than choosing other lawful options, 

potentially prejudicing the pipeline in 

the limited section 4 filing under Option 

1. 

b. Discussion 

111. We generally adopt the NOPR 

proposal regarding how capital structure 

must be reported on FERC Form No. 

501–G, but make several changes to 

address concerns raised by the 

commenters. As discussed above, the 

One-time Report is an informational 

filing required pursuant to NGA 

sections 10 and 14 that serves two 

purposes: (1) To help determine 

whether to initiate NGA section 5 

investigations of interstate natural gas 

pipelines’ rates and (2) as support for 

limited NGA section 4 filings pipelines 

may choose to make to reduce their 

rates to reflect the Tax Cuts and Jobs Act 

or the United Airlines Issuances. When 

used for the first purpose, the FERC 

Form No. 501–G is intended to provide 

a rough estimate of the pipeline’s return 

on equity before and after the Tax Cuts 

and Jobs Act or the United Airlines 

Issuances. Such an estimate will be one 

factor the Commission will refer to in 

deciding whether to exercise its 

discretion to initiate an NGA section 5 

rate investigation. For that purpose, the 

Commission desires to design the form 

in a manner that will produce an 

estimated return on equity that is as 

accurate as possible. Therefore, the 

Commission seeks to use a capital 

structure that is consistent with 

Commission policy. For that reason, the 

Commission finds it appropriate for the 

FERC Form No. 501–G to use a different 

capital structure than that used in the 

pipeline’s FERC Form No. 2 or 2–A, 

when it appears that the capital 

structure reported in the FERC Form No. 

2 or 2–A does not comply with 

Commission policy.132 Thus, as 

described below, the form will ask a 

series of factual questions, designed to 

result in a capital structure consistent 

with Commission policy. However, the 

form will not be used to actually 

establish rates in any NGA section 5 

investigation that the Commission may 

initiate. Rather, any rates determined in 

a section 5 investigation, including the 

capital structure, will be based on the 

record developed in the hearing. 

112. The Commission has used a 

similar approach to capital structure in 

its analysis of FERC Form No. 2 or 2– 

A data in recent years for purposes of 

deciding whether to initiate NGA 

section 5 rate investigations. Thus, 

when a pipeline has reported a capital 

structure in its FERC Form No. 2 or 2– 

A that appeared not to comply with the 

Commission’s capital structure policy, 

the Commission has used a hypothetical 

capital structure to determine the return 

on equity shown by the pipeline’s FERC 

Form No. 2 or 2–A cost and revenue 

data. For example, in its 2011 order 

establishing a hearing under NGA 

section 5 concerning the rates of Bear 

Creek Storage Company, L.L.C. (Bear 

Creek), the Commission stated that, 

because Bear Creek had used a 100 

percent equity capital structure in its 

FERC Form No. 2, the Commission had 

used a hypothetical capital structure to 

estimate that Bear Creek’s return on 

equity using Bear Creek’s FERC Form 

No. 2 cost and revenue information was 

over 20 percent. However, the 

Commission was careful to state in its 

hearing order that ‘‘in this order, we 

make no finding as to what should 

constitute a just and reasonable capital 

structure for Bear Creek. That is among 

the issues set for hearing in this order 

and should be decided consistent with 

the Commission capital structure 

policies.’’ 133 The Commission intends 

to take a similar approach with respect 

to any NGA section 5 rate investigations 

it initiates based on the return on equity 

estimated in the FERC Form No. 501–G. 

The hearing order will make no finding 

as to what would constitute a just and 

reasonable capital structure for the 

pipeline in question, regardless of what 


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134High Island Offshore System, L.L.C., 110 FERC 

¶ 61,043, at P 147 (2005). 

135The Commission notes that this capital 

structure is also consistent with the capital 

structures the Commission typically approves in 

litigated rate cases for pipelines that do issue their 

own publically traded debt. Transok, Inc., 70 FERC 

¶ 61,177, at 61,554 (1995) (58.49 percent equity 

ratio); Panhandle Eastern Pipe Line Co., Opinion 

No. 395, 71 FERC ¶ 61,228, at 61,827 (1996) (61.79 

percent equity ratio); Panhandle Eastern Pipe Line 

Co., Opinion No. 404, 74 FERC ¶ 61,109, at 61,359 

(1996) (59.97 percent equity ratio); 

Transcontinental Gas Pipe Line Corp., Opinion No. 

414–A, 84 FERC ¶ 61,084, at 61,419 (1998) (57.58 

percent equity ratio). 

136 18 CFR part 201. 

type capital structure was required to be 

used in the FERC Form No. 501–G. The 

capital structure issue will be included 

in the hearing, and the Commission will 

have the burden of persuasion under 

NGA section 5 to support any rate 

reduction, including any capital 

structure used to support the rate 

reduction. 

113. The Commission recognizes that 

when the FERC Form No. 501–G is used 

for its second purpose—as support for 

the percentage rate reduction proposed 

in a pipeline’s limited NGA section 4 

rate case filing—the FERC Form No. 

501–G does serve a ratemaking purpose. 

However, as discussed above, pipelines 

are permitted to submit an Addendum 

to their FERC Form No. 501–G if they 

believe that the form inaccurately 

represents their financial situation. A 

pipeline may propose to use the 

percentage cost of service reduction 

calculated in its Addendum in its 

limited NGA section 4 rate filing. Thus, 

a pipeline may propose to use a capital 

structure other than that used in its 

FERC Form No. 501–G in its limited 

NGA section 4 rate filing. For example, 

Boardwalk provides comments on its 

specific financial situation; although 

this information is not relevant to 

developing a form for the entire natural 

gas pipeline industry, it may prove 

relevant in evaluating whether further 

procedures will be necessary to address 

the consequences of the Tax Cuts and 

Jobs Act for Boardwalk’s pipelines, and 

we encourage Boardwalk to include 

such information when it submits its 

One-time Reports. 

114. The Commission is making two 

changes to the treatment of capital 

structure in the FERC Form No. 501–G, 

as proposed in the NOPR. First, the 

Commission has modified page 4 of the 

proposed FERC Form No. 501–G in 

response to Kinder Morgan’s concerns 

that, as proposed, the form requires the 

pipelines to state an opinion as to 

whether the capital structure reported in 

their FERC Form No. 2 or 2–A complies 

with the Commission’s capital structure 

policies. Although the Commission does 

not concede the point that it lacks the 

authority under NGA section 10 or 14 to 

compel a pipeline to state whether it 

complies with an established policy, we 

recognize that such a requirement is 

unnecessary in order to achieve the 

goals of this rulemaking. Instead of 

asking the respondent its position with 

regard to whether its capital structure 

complies with Opinion No. 414–A, the 

form now includes a statement 

explaining how the Commission will 

use the respondent’s data to perform our 

own Opinion No. 414–A analysis. Page 

4 of the proposed FERC Form No. 

501–G now asks respondents a series of 

factual questions about its actual capital 

structure. The form will automatically 

select from the data provided to show 

the Commission’s default presumed 

capital structure under its Opinion No. 

414–A analysis, but will not require the 

respondent to apply the Commission’s 

position as if it was the pipeline’s. 

115. Second, as requested by Enable 

Interstate Pipelines, the Commission 

will modify the hypothetical capital 

structure used in the FERC Form No. 

501–G, for those pipelines which the 

form considers ineligible to use their 

own or their parent’s capital structure. 

As Enable Interstate Pipelines point out, 

in an NGA section 4 rate case in HIOS 

the Commission adopted a policy of 

basing a hypothetical capital structure 

on the average capital structure of the 

companies in the proxy group used for 

purposes of determining ROE. The 

Commission explained that ‘‘this 

assures a match between the financial 

risk inherent in the DCF analysis used 

to develop return on equity and the 

hypothetical capital structure.’’ 134 The 

FERC Form No. 501–G uses the 10.55 

percent ROE determined in El Paso. The 

average capital structure of the proxy 

group in that rate case was 

approximately 57 percent equity and 43 

percent debt.135 Accordingly, the 

Commission is revising the FERC Form 

No. 501–G to use a hypothetical capital 

structure of 57 percent equity and 43 

percent debt. This revision should also 

help address Boardwalk’s concern that 

the 50 percent equity/50 percent debt 

capital structure in the proposed FERC 

Form No. 501–G is financially 

unrealistic in today’s market conditions. 

7. Accumulated Deferred Income Taxes 

116. Accumulated Deferred Income 

Taxes (ADIT) balances are accumulated 

on the regulated books and records of 

interstate natural gas pipelines based on 

the requirements of the Commission’s 

Uniform System of Accounts.136 ADIT 

balances arise from differences between 

the method of computing taxable 

income for reporting to the IRS and the 

method of computing income for 

regulatory accounting purposes. The 

Commission’s regulatory accounting 

requirements then serve to inform the 

development of a natural gas pipeline’s 

rates, including the depreciation and 

ADIT ratemaking components. The most 

significant cause for differences between 

regulatory accounting and tax income is 

the use of straight-line depreciation 

rates for accounting and ratemaking 

purposes and the use of accelerated 

depreciation rates for federal income tax 

reporting purposes. As such, 

depreciation expense is higher for tax 

reporting purposes than that calculated 

for accounting and ratemaking 

purposes, resulting in higher taxes 

computed for accounting and 

ratemaking purposes than the taxes 

actually owed to the IRS authorities, in 

the early years of the property’s service 

life. This creates an ADIT liability. In 

later years, depreciation expense is 

lower for tax reporting purposes than 

that calculated for accounting and 

ratemaking purposes, resulting in lower 

taxes computed for accounting and 

ratemaking purposes than the taxes 

actually owed to the IRS and reductions 

to the ADIT liability. Ultimately, at the 

end of the property’s service life, the 

cumulative depreciation under either 

method are equal and the ADIT liability 

will be reduced to zero. 

117. ADIT generally impacts regulated 

natural gas pipelines’ ratemaking either 

by decreasing rate base, in the case of an 

ADIT liability, or increasing rate base, in 

the case of an ADIT asset. As a result of 

the reduction in the federal corporate 

income tax rate, taxes which have been 

previously deferred and reflected in 

ADIT will be owed to the IRS based on 

the 21 percent tax rate, rather than the 

35 percent tax rate used to recognize the 

ADIT initially. The difference between 

the already recognized ADIT based on a 

35 percent tax rate and the recomputed 

deferred taxes, which will actually be 

owed to the IRS, at a 21 percent tax rate 

requires an adjustment to ADIT balances 

for the excess or deficiency. 

Notwithstanding potential future 

Commission action in the ADIT NOI on 

how to treat excess ADIT or deficiency 

ADIT, these balances and the associated 

amortization are essential in 

appropriately computing a total cost of 

service. 

118. As discussed, the Commission is 

implementing in this Final Rule FERC 

Form No. 501–G as a basis for 

determining whether a natural gas 

pipeline may be over-recovering its cost 

of service, and thus whether there 

should be further investigation pursuant 

to NGA section 5. FERC Form No. 

501–G is designed to collect financial 


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137NOPR, FERC Stats. & Regs. ¶ 32,725 at P 26. 

138See proposed FERC Form No. 501–G, page 2, 

lines 13–17. All references to FERC Form No. 

501–G line numbers in this Final Rule are to the 

proposed form as contained in the NOPR. Certain 

line numbers have been modified in the final 

version of the form as discussed below. 

139See proposed FERC Form No. 501–G, page 1, 

line 31. 

140 INGAA Comments at 22; Boardwalk 

Comments at 13–15; Spectra Comments at 7, 22; 

Kinder Morgan Comments at 28; National Fuel 

Comments at 4–6; Dominion Energy Comments at 

3–4; EQT Midstream Comments at 8; Tallgrass 

Pipelines Comments at 7–8; Williams Comments at 

9; Berkshire Hathaway Comments at 5; Southern 

Star Comments at 9. 

141ADIT NOI, 162 FERC ¶ 61,223. 

information to evaluate the impact of 

the Tax Cuts and Jobs Act and the 

United Airlines Issuances on the 

pipeline’s cost of service, and to inform 

stakeholders, the Commission, and all 

interested parties regarding the 

continued justness and reasonableness 

of the pipeline’s rates after the income 

tax reduction and elimination of MLP 

pipeline income tax allowances.137

119. As proposed, the FERC Form No. 

501–G would require pipelines to use 

calendar year 2017 ADIT balances as 

reported in their 2017 FERC Form Nos. 

2 and 2–A in calculating rate base.138

The FERC Form No. 501–G would also 

require the pipelines to reduce their 

income tax allowance by an amount 

reflecting the first year’s amortization of 

excess ADIT resulting the reduced 

income tax rates under the Tax Cuts and 

Jobs Act.139

a. Comments 

120. Several commenters filed similar 

comments on this issue.140 They are 

concerned that FERC Form No. 501–G’s 

proposed treatment of ADIT and related 

amortization of excess ADIT is 

inextricably linked with the 

Commission’s Notice of Inquiry on the 

effect of the Tax Cuts and Jobs Act on 

Commission jurisdictional rates.141

These commenters insist that resolution 

of the requested areas of comment in the 

ADIT NOI on a number of issues 

regarding the details and effect of the 

appropriate treatment of ADIT as a 

result of the lower tax rates in the Tax 

Cuts and Jobs Act may impact the 

excess ADIT amounts that are entered in 

FERC Form No. 501–G, which will be 

filed with the Commission prior to any 

ADIT NOI resolution. According to 

these commenters, excess ADIT 

amounts are entered on Lines 13–17 on 

Page 2 of FERC Form No. 501–G for 

purposes of calculating rate base, and 

that results in the annual amortization 

figure entered in Line 31 on page 1 of 

the Form for purposes of calculating the 

tax allowance. These commenters note 

that the ADIT NOI seeks comments 

concerning potential adjustments to 

pipelines’ rate base relating to, and 

amortization of, excess or deficient 

ADIT; whether and how excess or 

deficient ADIT should be reflected in 

pipelines’ rates; and the treatment of 

excess ADIT associated with assets that 

pipelines sell or retire after the effective 

date of the Tax Cuts and Jobs Act. 

Without this guidance, they argue, 

pipelines will likely make individual 

judgments about the treatment of their 

ADIT balances, which will ultimately 

result in different inputs into their FERC 

Form No. 501–G from the final 

resolution. Thus, these commenters 

argue that the information would be 

highly varied and not comparable, 

which would hinder the Commission in 

evaluating pipelines’ rates. With the 

lack of clarity for these outstanding 

issues, these commenters contend that it 

will be nearly impossible to choose from 

among the four options available. The 

commenters are concerned that the 

proposed information in FERC Form No. 

501–G and related amortization in the 

indicative rate reduction will prejudge 

the outcome of the ADIT NOI 

rulemaking. These commenters insist 

that, as required by the Administrative 

Procedure Act, these issues should be 

addressed through adequate notice and 

comment procedures. In addition to the 

uncertainty originating from the 

resolution in the ADIT NOI, Berkshire 

Hathaway notes that the Commission is 

not the only regulatory agency 

evaluating the impact of the Tax Cuts 

and Jobs Act. Berkshire Hathaway 

further notes that both the Securities 

Exchange Commission (SEC) and the 

Financial Accounting Standards Board 

must set standards for financial 

reporting that address the reduction in 

the federal corporate income tax rate. 

Thus, Berkshire Hathaway states that 

although it has recorded the impacts of 

the Tax Cuts and Jobs Act in its FERC 

Form No. 2, it considers the amounts 

recorded, and the interpretations related 

to the financial reporting of bonus 

depreciation and regulatory liability 

amortization, to be provisional and 

subject to changes during the 

measurement period. Therefore, the 

commenters urge that the Commission 

consider the final resolution in the 

ADIT NOI proceeding before requiring 

the pipelines to file their FERC Form 

No. 501–G. 

121. The Oklahoma AG believes that 

the NOPR does not include the effects 

of excess ADIT on the revenue 

requirements of interstate natural gas 

pipelines and does not agree with this 

approach. Instead, the Oklahoma AG 

believes that the most effective and 

efficient means for resolving excess 

ADIT for interstate natural gas pipelines 

would be to include the amortization of 

excess ADIT in the FERC Form No. 501– 

G rather than awaiting conclusion of the 

open-ended ADIT NOI process. 

122. Enable Interstate Pipelines, 

Spectra, and National Fuel argue that 

establishing a generic policy regarding 

the treatment of ADIT ignores the 

complexity of the issue. They argue that 

the level of ADIT attributed to an entity 

depends on where (among other things) 

that entity’s assets are in their 

depreciable lives (for tax purposes and 

for ratemaking purposes), what 

transactions the entity has engaged in in 

the past, what assets have been fully 

depreciated, and differences in timing 

between book depreciation and tax 

depreciation. National Fuel notes that 

because its fiscal year is not on a 

calendar year basis, the applicable 

federal tax rate for fiscal year 2018 will 

be a composite tax rate, not the 21 

percent specified in FERC Form No. 

501–G. National Fuel insists that 

requiring pipelines with non-calendar 

year bases to utilize a 21 percent federal 

tax rate will yield incorrect and invalid 

results. National Fuel notes that the 

Commission has approved differing rate 

treatments in its rate cases. Because of 

expected differences from the FERC 

Form No. 501–G assumptions, National 

Fuel requests that the Commission 

modify the form to allow flexibility in 

regards to the form’s inputs in order to 

ensure a calculation of valid results. 

123. Spectra argues that FERC Form 

No. 501–G has erroneous built-in 

features that reduce rate base by the 

total regulatory liability reported on 

page 278 of the 2017 FERC Form No. 2. 

Spectra states that for many pipelines, a 

substantial portion of that regulatory 

liability is related to deferred income 

taxes. Also, Spectra states that FERC 

Form No. 501–G requires a pipeline to 

reduce its cost of service by the annual 

amortization of the excess ADIT 

regulatory liability. According to 

Spectra, this reduces rates twice for the 

same regulatory liability. 

124. LDC Coalition notes that 

pipelines will have adjusted their ADIT 

balances to reflect the change in the 

federal corporate income tax rate by the 

time they make their FERC Form No. 

501–G filing. LDC Coalition speculates 

that pipelines may use several 

alternatives to recalculate ADIT and 

then account for the excess ADIT. LDC 

Coalition states that although the 

pipeline may simply be transferring a 

previously booked item from its FERC 

Form No. 2 to the FERC Form No. 501– 

G, the Commission and customers 

reviewing the pipeline filing will have 


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142Boardwalk Comments at 14. 

143 INGAA Comments at 23; Boardwalk 

Comments at 14; Spectra Comments at 7–8; Kinder 

Morgan Comments at 28; Williams Comments at 9; 

Millennium Comments at 10; Tallgrass Pipelines 

Comments at 6, 9, 12; EQT Midstream Comments 

at 5, 8; Dominion Energy Comments at 4–5; 

National Fuel Comments at 5; Berkshire Hathaway 

Comments at 4–6; Southern Star Comments at 9– 

10. Similarly, LDC Coalition argues that the 

staggered timing of this proceeding and the ADIT 

NOI proceeding may make it difficult to determine 

how pipelines have adjusted their ADIT balances in 

calculating their costs in the FERC Form No. 

501–G filings. LDC Coalition Comments at 22. 

144 INGAA Comments at 23; Boardwalk 

Comments at 14; Spectra Comments at 8; Williams 

Comments at 9; Millennium Comments at 10; 

Tallgrass Pipelines Comments at 12; EQT 

Midstream Comments at 2, 8–9; Dominion Energy 

Comments at 4. 

145 INGAA Comments at 23; Boardwalk 

Comments at 14; Williams Comments at 9–10; 

Millennium Comments at 10; TransCanada 

Comments at 3–4; Tallgrass Pipelines Comments at 

12; EQT Midstream Comments at 9; Dominion 

Energy Comments at 4; National Fuel Comments at 

6; Southern Star Comments at 3, 10. 

146 INGAA Comments at 4, 22–23; Boardwalk 

Comments at 5, 13–15; Spectra Comments at 6–9; 

Kinder Morgan Comments at 28–29; Williams 

Comments at 3, 9; Millennium Comments at 2, 9– 

10; Tallgrass Pipelines Comments at 4–9, 11–12; 

EQT Midstream Comments at 2, 8–9; Dominion 

Energy Comments at 2–5; National Fuel Comments 

at 4–6; Berkshire Hathaway Comments at 3–6; 

Southern Star Comments at 3, 9–10. 

147 Inquiry Regarding the Commission’s Policy for 

Recovery of Income Tax Costs, Order on Rehearing, 

164 FERC ¶ 61,030 (2018). 

148This change will reduce to zero on the FERC 

Form No. 501–G line items for Accumulated 

Deferred Income Taxes (Account 190), 

Accumulated Deferred Income Taxes–Other 

Property (Account 282), and Accumulated Deferred 

Income Taxes–Other (Account 283). See FERC Form 

No. 501–G, page 2, lines 13–15. The pipeline 

should also remove any sums related to ADIT from 

Other Regulatory Liabilities (Account 254) and 

Other Regulatory Assets (Account 182.3). See FERC 

Form No. 501–G, page 2, lines 16–17. The 

Implementation Guide includes more specific 

instructions for the FERC Form No. 501–G. 

149See 18 CFR 154.305(a) (‘‘An interstate pipeline 

must compute the income tax component of its 

cost-of-service by using tax normalization for all 

transactions.’’); 18 CFR 154.305(b)(1) (‘‘Tax 

normalization means computing the income tax 

Continued 

no transparency in how an adjustment 

potentially involving many millions of 

dollars was calculated. To obtain better 

transparency, LDC Coalition requests 

that the Commission require pipelines 

to file an accompanying spreadsheet 

that provides how they recalculated 

ADIT and excess ADIT balances. In 

addition, LDC Coalition requests that 

the Commission include within the 

scope of hearing issues whether a 

pipeline has properly calculated ADIT 

for purposes of its FERC Form No. 

501–G and concurrent limited NGA 

section 4 rate reduction filing pursuant 

to proposed § 154.404. AGA and APGA 

also believe that ratepayers should be 

allowed to comment on a pipeline’s 

proposed treatment of ADIT. 

125. Commenters also raise concerns 

regarding the uncertainty surrounding 

the rate treatment of ADIT for those 

MLP pipelines or other pass-through 

entities that eliminate an income tax 

allowance pursuant to the United 

Airlines Issuances. For instance, 

Boardwalk argues that the uncertainty 

surrounding how to handle ADIT is 

particularly problematic for MLP 

pipelines that own pipelines that are no 

longer permitted an income tax 

allowance in their rates under the 

Revised Policy Statement but still have 

large ADIT balances on their FERC 

books.142

126. Spectra further argues that the 

proposed FERC Form No. 501–G treats 

certain entities as though they will not 

be permitted an income tax allowance 

going forward, but requires those same 

entities to carry-over historic ADITrelated balances and costs inputs. 

Spectra asserts that if there is no income 

tax liability, there should be no ADIT 

and associated adjustments. 

Accordingly, Spectra contends that 

FERC Form No. 501–G inappropriately 

requires such entities to reduce rate base 

by the amount of ADIT and reduce the 

total cost of service by the amortization 

of the excess ADIT Regulatory Liability 

balance. Spectra claims that, in the 

absence of an income tax allowance, 

ADIT is being used to provide a refund 

and violates precedent against 

retroactive ratemaking. Accordingly, 

Spectra argues that FERC Form No. 

501–G data entry for ADIT amortization 

should be zero for entities that are 

disallowed an income tax allowance 

pursuant to the United Airlines 

Issuances. 

127. In sum, commenters argue that 

the uncertainty regarding ADIT may 

(1) result in misleading or inaccurate 

information provided in the FERC Form 

No. 501–G filings, particularly the 

inputs related to ADIT; 143 (2) 

discourage pipelines from selecting the 

option to file a limited section 4 rate 

case; 144 and (3) reduce the likelihood 

pipelines and shippers will enter into 

settlements.145 Commenters urge that 

the Commission consider the final 

resolution of the issues in the pending 

ADIT NOI proceeding before the 

issuance of the Final Rule in this 

proceeding or at least before pipelines 

are required to file their FERC Form No. 

501–G.146

b. Discussion 

128. The majority of pipeline 

commenters recommend that the 

Commission delay the requirement to 

file FERC Form No. 501–G until a Final 

Rule is issued in the ADIT NOI 

proceeding. The Commission concludes 

that such a delay is unnecessary in light 

of the steps we take below. 

129. The Commission is setting forth 

its policy concerning the treatment of 

ADIT when the tax allowances of passthrough pipelines (including MLP 

pipelines) are eliminated, and the 

Commission modifies the FERC Form 

No. 501–G to reflect that policy. The 

Commission declines to make other 

changes from the NOPR proposal 

because, as explained below, the 

Commission’s existing ADIT policies 

provide sufficient guidance for the 

purposes of this Final Rule. 

i. Treatment of ADIT When a PassThrough Pipeline’s Income Tax 

Allowance Is Eliminated 

130. In response to the concerns 

raised by Spectra, Boardwalk, and 

others, the Commission takes two steps 

to address treatment of ADIT when a 

pass-through entity eliminates its 

income tax allowance. 

131. First, in the rehearing of the 

Revised Policy Statement (which is 

issuing concurrently with this Final 

Rule),147 the Commission announces its 

intent to permit a pass-through pipeline 

to eliminate ADIT from its cost of 

service if that pass-through pipeline 

eliminates its income tax allowance 

pursuant to the United Airlines 

Issuances policy. Thus, the Commission 

does not intend to require a passthrough pipeline to return ADIT to its 

customers or to adjust its rate base by 

any outstanding ADIT balance. 

Although non-binding, this guidance 

should help pipelines more efficiently 

evaluate their options pursuant to the 

Final Rule. This clarification may also 

facilitate potential settlement 

negotiations between pipelines and 

customers. 

132. Second, the Commission 

modifies the proposed Form No. 501–G 

so that, if a pass-through entity states 

that it does not pay taxes, the form will 

not only eliminate its income tax 

allowance, but will also eliminate 

ADIT.148 Several reasons support this 

change. As an initial matter, this 

modification will provide that the FERC 

Form No. 501–G defaults to providing 

data consistent with the guidance the 

Commission is concurrently providing 

on rehearing of the Revised Policy 

Statement. Commission and IRS 

regulations regarding normalization 

(including ADIT) only apply to entities 

with an income tax allowance 

component in their regulated cost-ofservice rates.149 ADIT is a regulatory 


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component as if transactions recognized in each 

period for ratemaking purposes are also recognized 

in the same amount and in the same period for 

income tax purposes.’’); 18 CFR 154.305(b)(4) 

(‘‘Income tax component means that part of the 

cost-of-service that covers income tax expenses 

allowable by the Commission.’’); 26 U.S.C. 

168(i)(9)(A) (‘‘the taxpayer must, in computing its 

tax expense for purposes of establishing its cost of 

service for rate-making purposes . . . use a method 

of depreciation with respect to such property that 

is the same as, and a depreciation period for such 

property that is no shorter than, the method and 

period used to compute its depreciation expense for 

such purposes. . . .’’) (emphasis added). 

Algonquin Gas Transmission Co., 76 FERC 

¶ 61,075, at 61,449 (1996); see also 18 CFR 

154.305(c)(2) (‘‘rate base reductions or additions’’ 

for ADIT ‘‘must be limited to deferred taxes related 

to rate base, construction, or other costs and 

revenues affecting jurisdictional cost-of-service’’) 

(emphasis added); 18 CFR 154.305(d)(1) 

(requirements relating to excess or deficient ADIT 

balances apply where the discrepancy is ‘‘a result 

of changes in tax rates’’ or where ‘‘the rate applicant 

has not provided deferred taxes in the same amount 

that would have accrued had tax normalization 

always been applied.’’). 

150Arco Pipe Line Co., Opinion No. 351, 52 FERC 

¶ 61,055, at 61,238 (1990). 

151 ‘‘The primary rationale for normalization is 

matching: The recognition in rates of the tax effects 

of expenses and revenues with the expenses and 

revenues themselves.’’ Regulations Implementing 

Tax Normalization for Certain Items Reflecting 

Timing Differences in the Recognition of Expenses 

or Revenues for Ratemaking and Income Tax 

Purposes, Order No. 144, FERC Stats. & Regs. 

¶ 30,254 at 31,522 (1981), reh’g denied, Order No. 

144–A, FERC Stats. & Regs. ¶ 30,340 (1982), aff’d, 

Public Systems v. FERC, 709 F.2d 73 (D.C. Cir. 

1983). 

152See Public Utilities, 894 F.2d at 1382 (noting 

that ‘‘[t]ax normalization sought to ‘match’ the 

timing of a customer’s contribution toward a cost 

with enjoyment of any offsetting tax benefit,’’ but 

finding the passage of the NGPA which resulted in 

El Paso no longer using cost-of-service rates 

‘‘mooted the whole question to which 

normalization was the answer’’). 

153City of Piqua v. FERC, 610 F.2d 950, 954 (D.C. 

Cir. 1979). 

154Public Utilities Comm’n of State of Cal. v. 

FERC, 894 F.2d 1372 (D.C. Cir. 1990). Specifically, 

Public Utilities held that requiring a pipeline to 

credit ratepayers for earnings on an excess ADIT 

balance where the pipeline switched from cost-ofservice rates to ceiling prices violated the rule 

against retroactive ratemaking. As the court found 

in Public Utilities, ADIT ‘‘is composed entirely of 

rate revenue that [the pipeline] has already 

collected. Refund of such property, or its earnings, 

would effectively force [the pipeline] to return a 

portion of rates approved by FERC, and collected 

by [the pipeline].’’ Id. at 1383. The D.C. Circuit 

explained that to the extent any basis for requiring 

the credit to ratepayers rested on the view that the 

pipeline’s prior cost-of-service rates were ‘‘in 

retrospect too high’’ or ‘‘unjust and unreasonable’’ 

then the credit for earnings on previously 

accumulated ADIT sums violated the rule against 

retroactive ratemaking. Id. at 1380, 1382. 

155Public Systems, 709 F.2d at 85 (rejecting the 

notion ‘‘that ratepayers have an ownership claim’’ 

to the ADIT balance); Public Utilities, 894 F.2d at 

1381 (‘‘The Commission and this Court have both 

rejected’’ ‘‘the notion that under normalization 

accounting customers enjoy an equitable interest in 

a utility’s deferred tax account.’’); Order No. 144, 

FERC Stats. & Regs. ¶ 30,254 at 31,539 (addressing 

the ‘‘erroneous premise that a loan is being made 

by ratepayers to utilities’’ through the normalization 

process’’ and stating that ratepayers do not ‘‘have 

an ownership claim or equitable entitlement to the 

‘loaned monies’’’); id. at 31,539 n.75 (‘‘This is not 

to say that customers do not pay rates that recover 

deferred taxes. They do. But paying deferred taxes 

in rates does not convey and ownership or 

creditor’s right.’’). 

156 Lakehead Pipe Line Co. L.P., 75 FERC 

¶ 61,181, at 61,594 (1996). Moreover, there would 

be practical problems with maintaining such a 

tracker as many oil pipeline rates have never have 

been subject to a cost-of-service rate proceeding. For 

these pipelines, there is no cost-of-service income 

tax allowance which has been established. 

157The Commission’s primary justification for its 

decision to adopt tax normalization was ‘‘the 

matching principle: as a matter of fairness, 

customers who pay an expense should get the tax 

benefit that accompanies the expense. . . .’’ Public 

Systems, 709 F2d at 80. 

158For example, ADIT is eliminated (not returned 

to shippers) when the pipeline must pay these 

deferred taxes to the federal government as a result 

of a sale of the asset. Enbridge Pipelines (KPC), 100 

FERC ¶ 61,260, at PP 158–162 (2002). 

159Of course, we anticipate that any pass-through 

entity claiming an income tax allowance in the 

Addendum to Form No. 501–G will include the 

previously accumulated sums in ADIT. 

construct to ensure that regulated 

entities do not earn a return on cost-free 

capital based upon timing differences 

between federal and state tax liability 

and Commission ratemaking.150 The 

purpose of normalization is matching 

the pipeline’s cost-of-service expenses 

in rates with the tax effects of those 

same cost-of-service expenses.151 If 

there is no income tax allowance in 

Commission rates, there is no basis for 

the ‘‘matching’’ function of 

normalization 152 and no liability for the 

deferred taxes reflected in ADIT. In the 

absence of ADIT, there is no ADIT 

adjustment to rate base or amortization 

allowance to be reflected in cost-ofservice rates. 

133. Moreover this modification to the 

FERC Form No. 501–G comports with 

retroactive ratemaking principles. The 

rule against retroactive ratemaking bars 

‘‘the Commission’s retroactive 

substitution of an unreasonably high or 

low rate with a just and reasonable 

rate.’’ 153 As relevant here, when a passthrough pipeline eliminates its income 

tax allowance consistent with the 

United Airlines Issuances policy, 

maintaining ADIT in cost of service 

would violate retroactive ratemaking by 

requiring pipelines to refund to shippers 

tax costs the pipeline collected in past 

rates for payment to the IRS pursuant to 

the Commission’s pre-United Airlines 

policy. This analysis is supported by the 

D.C. Circuit’s Public Utilities decision 

which held that requiring a pipeline to 

credit ratepayers for earnings on an 

excess ADIT balance or refund the 

balance to ratepayers violated 

retroactive ratemaking where the 

pipeline switched to statutory 

proscribed rate ceilings from cost-ofservice rates, meaning that the rates no 

longer included a cost-of-service 

normalization of income tax costs.154

134. Finally, shippers have no equity 

interest in ADIT that justifies 

maintaining ADIT in rates or alleviates 

the above retroactive ratemaking 

concerns. The Commission and the D.C. 

Circuit have rejected arguments based 

on the misconception that ADIT is a 

cash reserve over which ratepayers have 

an ownership claim or equitable 

interest.155 Consistent with these 

holdings, the Commission has also 

explained that ADIT is not a true-up or 

tracker of money owed to shippers.156

Rather, under the Commission’s preUnited Airlines policies involving tax 

allowances for pass-through entities, 

normalization in past rates required 

ratepayers to pay their properly 

allocated share of the pipeline’s tax 

expenses as matched to the ratepayers’ 

payment of straight-line depreciation 

costs.157 ADIT is not money owed to 

past or future ratepayers, but rather 

deferred taxes that are ultimately owed 

to the government.158

135. Accordingly, the informational 

FERC Form No. 501–G is likely to be the 

most useful if it removes ADIT 

whenever the income tax allowance is 

eliminated. Furthermore, although the 

Commission has made this adjustment 

to the FERC Form No. 501–G, a pipeline 

may propose alternative treatment of 

ADIT in the Addendum.159 Similarly, 

the removal of ADIT on FERC Form No. 

501–G (or any subsequent adjustments 

in the Addendum) may be reflected in 

the optional limited section 4 rate 

filings. Given that these section 4 rate 

filings reduce the pipeline’s rates and 

are entirely at the pipeline’s discretion, 

we do not think this modification is 

inappropriate. The Commission also 

emphasizes that this modification only 

applies to the FERC Form No. 501–G 

(and the optional limited section 4 

filings pursuant to § 154.404(a)). It does 

not establish a broader rule. Shippers 

and pipelines may advocate for a 

different treatment of ADIT in any 

future rate litigation. 

ii. Other ADIT Issues 

136. To the extent commenters 

request that the Commission delay 

issuance of this Final Rule until other 

issues raised in the ADIT NOI are 

resolved, the Commission believes that 

the commenters misconstrue the ADIT 

NOI proceeding. The ADIT NOI is a 

notice of inquiry that does not change 

or propose to change any existing 

ratemaking or accounting regulations. 

As noted by the Oklahoma AG, the 

ADIT NOI has an open ended process 

and may or may not result in any final 

rulemaking. The Commission has asked 


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160See, e.g., Accounting For Income Taxes, 

Docket No. AI93–5–000 (April 23, 1993), available 

at http://www.ferc.gov/enforcement/acct-matts/ 

docs/AI93-5-000.asp (AI93–5–000 Guidance). 

161See Tax Cuts and Jobs Act 13001(d), 131 Stat. 

at 2099–2100. 

162AI93–5–000 Guidance, Question 8: Changes In 

Tax Law Or Rates (emphasis added). 

163Tax Normalization for Certain Items Reflecting 

Timing Differences in the Recognition of Expenses 

or Revenues for Ratemaking and Income Tax 

Purposes, Order No. 144, FERC Stats. & Regs. 

¶ 30,254 (1981) (cross-referenced at 15 FERC 

¶ 61,133), order denying reh’g, lifting stay and 

clarifying order, Order No. 144–A, FERC Stats. & 

Regs. ¶ 30,340 (1982) (established 18 CFR 154.63a). 

The content of § 154.63a was later updated and 

moved to 18 CFR 154.305: Tax Normalization. 

Filing and Reporting Requirements for Interstate 

Natural Gas Co. Rate Schedules and Tariffs, Order 

No. 582, FERC Stats. & Regs. ¶ 31,025 (1995) (crossreferenced at 72 FERC ¶ 61,300). 

164NOPR, FERC Stats. & Regs. ¶ 32,725 at P 4. 

165 18 CFR part 201. 

166 Id. at General Instructions, No. VIII. 

for comment from the public on 

numerous ADIT-related questions as 

they relate to the proper implementation 

procedures on the various effects on 

cost-of-service rates resulting from the 

Tax Cuts and Jobs Act and the United 

Airlines Issuances. To the extent the 

Commission does change its ratemaking 

and accounting regulations, the 

implementation of any new instructions 

and policies will have only a 

prospective application. In the 

meantime, natural gas pipelines must 

follow the Commission’s existing 

ratemaking and accounting regulations 

concerning ADIT described below. 

137. Commenters argue that without 

the guidance resulting from the ADIT 

NOI proceeding, individual natural gas 

companies may not populate FERC 

Form No. 501–G in a consistent manner. 

However, we believe that this is not the 

case, because all ADIT-related data 

elements are to be taken directly from 

the natural gas companies’ FERC Form 

Nos. 2 and 2–A and their existing 

accounting records. The FERC Form 

Nos. 2 and 2–A data largely originates 

from the Commission’s Uniform System 

of Accounts (USofA) instructions. As 

such, the Commission’s existing USofA, 

among other things, contains 

instructions on balance sheet and 

statement of income accounts related to 

ADIT.160 Natural gas companies report 

all ADIT balances on their FERC Form 

Nos. 2 and 2–A. Thus, 2017 FERC Form 

Nos. 2 and 2–A prepared consistent 

with existing guidance should provide 

the amounts of the excess or deficiency 

ADIT balances as of December 31, 2017, 

after the enactment date of December 

22, 2017 of the Tax Cuts and Jobs Act. 

138. Finally, the IRS has accepted two 

methods to flow back any excess or 

deficiency ADIT since at least the Tax 

Reform Act of 1986. The Commission, 

consistent with current guidance and 

the Tax Cuts and Jobs Act directives,161

will continue to allow the use of either 

of these two methods: (1) The Average 

Rate Assumption Method (ARAM), 

which is the primary method, and (2) 

the Reverse South Georgia Method 

(RSGM), which is permitted as an 

exception, if a rate regulated company 

does not have vintage records for its 

plant assets to support the reversal of 

book/tax differences. 

139. When the Tax Cuts and Jobs Act 

passed on December 22, 2017, the effect 

of the federal income tax reduction from 

35 percent to 21 percent became known. 

Therefore, consistent with the 

Commission’s current accounting 

guidance in Docket No. AI93–5–000, 

natural gas companies are required to 

adjust their ‘‘deferred tax liabilities and 

assets for the effect of the change in tax 

law or rates in the period that the 

change is enacted.’’ 162 This guidance 

means that, as the Tax Cuts and Jobs Act 

was enacted before the end of the 2017 

calendar year, all natural gas companies’ 

2017 FERC Form Nos. 2 and 2–A filed 

April 2018 should have reflected 

recalculated deferred tax liabilities and 

assets consistent with the Tax Cuts and 

Jobs Act, even though the Tax Cuts and 

Jobs Act did not become effective until 

January 1, 2018. Specifically, the 

Commission’s AI93–5–000 Guidance at 

Question 8 provides the following: 

The adjustment shall be recorded in the 

proper deferred tax balance sheet accounts 

(Accounts 190, 281, 282 and 283) based on 

the nature of the temporary difference and 

the related classification requirements of the 

accounts. If as a result of action by a 

regulator, it is probable that the future 

increase or decrease in taxes payable due to 

the change in tax law or rates will be 

recovered from or returned to customers 

through future rates, an asset or liability shall 

be recognized in Account 182.3, Other 

Regulatory Assets, or Account 254, Other 

Regulatory Liabilities, as appropriate, for that 

probable future revenue or reduction in 

future revenue. That asset or liability is also 

a temporary difference for which a deferred 

tax asset or liability shall be recognized in 

Account 190, Accumulated Deferred Income 

Taxes or Account 283, Accumulated Deferred 

Income Taxes Other, as appropriate. 

140. Moreover, it has been a longstanding policy for the Commission to 

require natural gas companies to flow 

back the effects of timing differences 

between the Commission approved 

income tax allowances and the IRS tax 

liabilities.163 This Final Rule is also 

premised on the Commission’s concern 

that natural gas pipelines may be 

collecting unjust and unreasonable rates 

in light of the recent reduction in the 

federal corporate income tax rate in the 

Tax Cuts and Jobs Act, and that it may 

be appropriate to direct natural gas 

pipelines to reduce their rates to reflect 

the effects of the Tax Cuts and Jobs Act, 

or to establish proceedings to determine 

whether natural gas companies’ existing 

rates are no longer just and reasonable 

and establish new just and reasonable 

rates.164

141. With the precondition satisfied, 

the Commission’s guidance in AI93–5– 

000 at Question 8 continues with regard 

to the recognition of ADIT regulatory 

assets or liabilities: 

. . . [A]n asset or liability shall be recognized 

in Account 182.3, Other Regulatory Assets, or 

Account 254, Other Regulatory Liabilities, as 

appropriate, for that probable future revenue 

or reduction in future revenue. That asset or 

liability is also a temporary difference for 

which a deferred tax asset or liability shall 

be recognized in Account 190, Accumulated 

Deferred Income Taxes or Account 283, 

Accumulated Deferred Income Taxes Other, 

as appropriate. 

142. Further, the Commission’s 

USofA instructions for each of the 

referenced balance sheet accounts 

provide detailed guidance on how the 

accounting journal entries for the 

regulatory asset, in the case of a 

deficiency ADIT, or regulatory liability, 

in the case of excess ADIT, should be 

established and amortized to account for 

the flow-back of the deficiency or excess 

ADIT through the appropriate income 

statement accounts based on current 

guidance.165

143. With the amounts recorded in 

the appropriate accounts, consistent 

with the Commission’s existing 

instructions and guidance, there should 

be only limited variation in the natural 

gas companies’ financial information 

reported in their FERC Form Nos. 2 and 

2–A and the proposed FERC Form No. 

501–G. To the extent that further 

explanations for the reported financial 

information are necessary, natural gas 

companies are advised to provide such 

explanations in the footnotes to their 

financial statements.166 Any 

explanations or differences in reported 

financial information can also be 

provided in the optional Addendum 

that pipelines are permitted to file along 

with their FERC Form No. 501–G. As 

the Commission already has in place 

sufficient guidance in regards to 

classification and recording of ADITrelated amounts, the Commission does 

not expect any significant variations in 

how natural gas companies account for 

such amounts. Further, to the extent a 

natural gas pipeline did not prepare its 

2017 FERC Form Nos. 2 and 2–A 

consistent with the prior Commission 

guidance discussed above, the company 


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167See Entergy Services, Inc., Opinion No. 545, 

153 FERC ¶ 61,303, at P 156 (2015); as clarified 156 

FERC ¶ 61,196, at P 150 (2016) (Finding that past 

FERC Form No. 1s must be refiled to correct an 

ADIT amortization period mistake.). 

168 18 CFR 154.305(d): 

(d) Special rules. 

(1) This paragraph applies: . . . . or (ii) If, as a 

result of changes in tax rates, the accumulated 

provision for deferred taxes becomes deficient in, 

or in excess of, amounts necessary to meet future 

tax liabilities. 

(2) The interstate pipeline must compute the 

income tax component in its cost-of-service by 

making provision for any excess or deficiency in 

deferred taxes. 

169 18 CFR 154.305(c): 

(c) Reduction of, and addition to, Rate Base. 

(1) The rate base of an interstate pipeline using 

tax normalization under this section must be 

reduced by the balances that are properly 

recordable in Account 281, ‘‘Accumulated deferred 

income taxes-accelerated amortization property’’; 

Account 282, ‘‘Accumulated deferred income 

taxes—other property’’: and Account 283, 

‘‘Accumulated deferred income taxes—other.’’ 

Balances that are properly recordable in Account 

190, ‘‘Accumulated deferred income taxes,’’ must 

be treated as an addition to rate base. Include, as 

an addition or reduction, as appropriate, amounts 

in Account 182.3, Other regulatory assets, and 

Account 254, Other regulatory liabilities, that result 

from a deficiency or excess in the deferred tax 

accounts (see paragraph (d) of this section) and 

which have been, or are soon expected to be, 

authorized for recovery or refund through rates. 

(2) Such rate base reductions or additions must 

be limited to deferred taxes related to rate base, 

construction, or other costs and revenues affecting 

jurisdictional cost-of-service. 

170National Fuel Gas Supply Corp., May 22, 2012 

Settlement filed in Docket No. RP12–88, Article I, 

approved National Fuel Gas Supply Corp., 140 

FERC ¶ 61,114 (2012). This provision of the May 22, 

2012 Settlement remains unchanged and continues 

pursuant to Article II of the September 29, 2015 

Supplemental Stipulation and Agreement filed in 

Docket No. RP15–1310–000, approved National 

Fuel Gas Supply Corp., 153 FERC ¶ 61,170 (2015). 

171Further, even if there had been such a 

provision or work papers, it would have had no 

precedential value: ‘‘The Commission’s order 

approving this Stipulation shall not constitute 

approval or acceptance of any concept, theory, 

principle, or method underlying any of the rates or 

charges or any other matter identified in this 

Stipulation or in this proceeding.’’ May 22, 2012 

Settlement at Article XIII. 

172 Id. at Article VII. 

173See Koch Gateway Pipeline Co., 74 FERC 

¶ 61,088, at 61,277 (1996) (‘‘While the Commission 

is not bound to follow an IRS ruling for ratemaking 

purposes, we are reluctant to take action which 

would endanger a pipeline’s right to favorable tax 

treatment from the IRS.’’). 

174National Fuel reports its fiscal year is October 

1 through September 30. National Fuel’s 2017 FERC 

Form No. 2, page 122.9 (filed April 16, 2018). 

must make the appropriate 

corrections.167

144. FERC Form No. 501–G largely 

requires natural gas companies to 

transfer financial data directly from 

their FERC Form Nos. 2 and 2–A for 

purposes of examining their costs of 

service. FERC Form No. 501–G 

calculates an indicated cost of service 

(page 1) and rate base (page 2). The 

ADIT amounts that natural gas 

companies enter on lines 13–17 of page 

2 for purposes of calculating their rate 

base must be transferred directly from 

the companies’ 2017 FERC Form Nos. 2 

and 2–A. The 2017 FERC Form Nos. 2 

and 2–A do not necessarily provide the 

figure for Amortization of Excess/ 

Deficiency ADIT that the FERC Form 

No. 501–G requires natural gas 

companies to enter on page 1, line 31, 

for purposes of calculating the tax 

allowance included in cost of service. 

That is because this information will be 

reported in subsequent periods. 

However, as explained above, natural 

gas companies should already have this 

amount determined based on previous 

Commission and IRS guidance. 

Specifically, under current guidance, 

the Commission expects the flow-back 

of the excess regulatory liability or 

deficiency regulatory asset to occur over 

the remaining book life of the associated 

plant assets, because depreciation of 

plant assets is the primary driver of 

timing differences in taxes as they relate 

to natural gas companies. The 

Commission expects insignificant 

differences between proposed 

amortization periods by the natural gas 

companies and approved amortization 

periods by the Commission as they 

relate to items other than plant assets. 

Whenever there is a need for noting 

potential differences, natural gas 

companies may provide explanations in 

the optional Addendum that pipelines 

are permitted to file along with their 

FERC Form No. 501–G. 

145. Additionally, FERC Form No. 

501–G appropriately considers the 

amortization of excess ADIT balances as 

part of calculating the tax allowance 

included in cost of service. This is a 

requirement codified at § 154.305(d) of 

the Commission’s regulations.168 As 

described above, FERC Form No. 501– 

G, page 1, requires Amortization of 

Excess ADIT as part of the indicated 

cost of service. Further, FERC Form No. 

501–G appropriately adjusts rate base 

for ADIT balances. This is consistent 

with current guidance under 

§ 154.305(c) of the Commission’s 

regulations.169 On FERC Form No. 501– 

G, page 2, the rate base calculation 

removes the excess ADIT balance and 

adds the deficiency ADIT balance from/ 

to rate base. As discussed above, Spectra 

and Boardwalk expressed concern that 

proposed FERC Form No. 501–G 

provides that entities not permitted an 

income tax allowance going forward are 

still required to carry-over historic 

ADIT-related balances and costs inputs. 

Consistent with the discussion above, 

the Commission has modified FERC 

Form No. 501–G’s treatment of ADIT 

balances and amortization of excess or 

deficient ADIT. For pipelines that 

indicate that they are not a separate 

income taxpaying entity on FERC Form 

No. 501–G, page 1, Line 4, page 2 

eliminates the ADIT adjustment to rate 

base and does not require the pipeline 

to estimate the amortization of excess or 

deficient ADIT on page 1, Line 31. 

146. In summary, the Commission has 

existing and currently applicable 

regulations, instructions, and guidance 

necessary for natural gas companies to 

account properly for the effects of the 

Tax Cuts and Jobs Act. Further, 

§ 154.305 of the Commission’s 

regulations establishes the default 

treatment of ADIT balances and 

amortization thereof in rate base and the 

cost of service. For all the stated reasons 

discussed above, the Commission does 

not find persuasive commenters’ 

argument that there is a lack of guidance 

on how to account for and flow-back 

ADIT balances. 

147. National Fuel advocates that the 

Commission should permit pipelines 

flexibility in ADIT treatment in FERC 

Form No. 501–G. National Fuel states 

that the Commission has permitted 

differing rate treatment, including 

National Fuel’s. However, National Fuel 

does not provide any specific examples 

or citations. Therefore, it is not clear as 

to the nature of flexibility National Fuel 

is advocating. Further, as to National 

Fuel’s own cost of service, the 

Commission notes that National Fuel 

informed the Commission that the 

settlements underlying its currently 

effective rates are ‘‘black box’’ 

settlements.170 As is the case with most 

black box settlements, National Fuel’s 

May 22, 2012 and September 29, 2015 

Settlements did not contain cost-ofservice work papers. Therefore, it is not 

possible to confirm National Fuel’s 

claim that the Commission afforded 

differing treatment of ADIT in National 

Fuel’s currently effective rates.171 With 

regard to ADIT, the May 22, 2012 

Settlement provides that the settlement 

rates are consistent with IRS regulations 

with respect to normalization of any 

excess and/or deficiency in deferred 

income taxes.172 Commission 

normalization requirements are not 

inconsistent with the IRS normalization 

regulations.173 Notwithstanding, natural 

gas pipelines may suggest alternative 

ADIT treatment as part of an 

Addendum. 

148. National Fuel notes that because 

its fiscal year is not on a calendar year 

basis,174 the applicable federal tax rate 

for fiscal year 2018 will be a composite 

tax rate, not the 21 percent specified in 

FERC Form No. 501–G. National Fuel 


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175Order No. 144–A, FERC Stats. & Regs. ¶ 30,340 

at 30,128. 

176El Paso Natural Gas Co., L.L.C., 152 FERC ¶ 

61,039, at P 88 (2015) (El Paso). 

177See Distrigas Mass. Corp. v. FERC, 737 F.2d 

1208, 1212 (1st Cir. 1984) (describing the tax 

deferral as ‘‘highly advantageous’’ to regulated 

entities, noting that service providers ‘‘obtain the 

use of the ‘saved tax’ money until the time it falls 

due’’). See also United Gas Pipeline Co., Opinion 

No. 99, 13 FERC ¶ 61,044, at 61,096 (1980) 

(excluding undistributed subsidiary earnings from 

equity because funds not available for investment 

in jurisdictional activities). 

178El Paso, 152 FERC ¶ 61,039 at P 89. 

179NOPR, FERC Stats. & Regs. ¶ 32,725 at 

proposed 18 CFR 260.402(b)(1)(i); see id. P 26. 

believes that requiring pipelines with 

non-calendar year bases to utilize a 21 

percent federal tax rate will yield 

incorrect and invalid results. The 

Commission disagrees. National Fuel’s 

ADIT balances, as reported in its 2017 

FERC Form No. 2, should be 

recalculated to reflect the known 

reduction in the level of federal income 

tax as the result of the Tax Cuts and Jobs 

Act as of the enactment date of 

December 22, 2017 of the new law. 

Although National Fuel’s recalculation 

of its excess or deficiency ADIT may be 

more complex than that of other 

pipelines, if the recalculation is done 

consistent with the Commission’s 

USofA and the AI93–5–000 Guidance, 

the FERC Form No. 2 data should be 

sufficient to determine the needed 

adjustment to rate base. Further, with 

regard to FERC Form No. 501–G, the 

Commission notes that the Commission 

has assigned National Fuel to reporting 

Group III. That group is not required to 

file their FERC Form No. 501–Gs until 

84 days after the effective date of this 

Final Rule. By that required reporting 

time, National Fuel’s fiscal year issue 

will be moot, and its FERC Form No. 

501–G results will be valid. 

149. Spectra notes that FERC Form 

No. 501–G reduces rate base by the full 

ADIT balance existing at the end of 

calendar year 2017 without any 

adjustment for the amortization of 

excess ADIT, but at the same time the 

FERC Form No. 501–G reduces the tax 

allowance included in the cost of 

service by an amount equaling the 

annual amortization of excess ADIT. 

Spectra contends that such treatment 

reduces rates twice for the same 

regulatory liability. Spectra is incorrect. 

The Commission’s rationale for 

subtracting accumulated deferred taxes 

from rate base was discussed in Order 

No. 144–A: 

The deduction of accumulated deferred taxes 

from rate base . . . is intended to reflect the 

lower cost of service that a utility achieves 

by its use of the cash flow from deferred 

taxes in place of debt and equity capital.175

150. The Commission is modifying 

FERC Form No. 501–G in response to 

Spectra’s argument that the amortization 

of excess ADIT balances in the cost of 

service (in combination with a rate base 

adjustment reflecting the full ADIT 

balance) reduces rates twice. As a 

pipeline amortizes its excess ADIT (i.e., 

credits excess ADIT in determining the 

current period’s tax allowance), the 

ADIT balance subtracted from rate base 

will decline, with the result that net rate 

base will be higher than it would be 

absent the amortization of excess of 

ADIT. The Commission acknowledges 

that the FERC Form No. 501–G in the 

NOPR was based upon an historic test 

period with only a single static 

adjustment to cost of service to account 

for the change in the income allowance 

as a result of the Tax Cuts and Jobs Act. 

The effect of Spectra’s request is to 

make the adjustment dynamic by 

reflecting an initial amortization of 

excess ADIT in rate base. The 

Commission is making a change to 

reflect a reduction to Other Regulatory 

Liabilities for the Net Amortization of 

Excess and/or Deficient ADIT in the 

FERC Form No. 501–G. 

151. LDC Coalition requests that the 

Commission require natural gas 

companies to file an accompanying 

spreadsheet that provides how 

companies recalculated ADIT and 

excess ADIT balances. In addition, LDC 

Coalition and AGA request that the 

Commission discuss within the scope of 

hearing issues whether a natural gas 

company has properly calculated ADIT 

for purposes of its FERC Form No. 501– 

G and concurrent limited NGA section 

4 rate reduction filing pursuant to 

proposed § 154.404. The Commission 

declines to do so. The Commission has 

previously provided guidance to natural 

gas companies on how to properly 

recalculate ADIT balances and 

determine amortization amounts of 

excess or deficiency ADIT balances. 

With regard to all the financial data 

reported in FERC Form Nos. 2 and 2– 

A, natural gas companies are required to 

attest to the conformity of that data, in 

all material respects, with the 

Commission’s applicable USofA and to 

have the submission signed by an 

independent certified public 

accountant. FERC Form No. 501–G is 

not the vehicle for parties to challenge 

the validity of FERC Form Nos. 2 and 

2–A data. In addition, the data 

underlying the calculation of natural gas 

companies’ amortization of excess or 

deficiency ADIT balances can be 

extensive, and the calculation itself 

requires iterative calculations extending 

over the longer of the Commission’s or 

the IRS’ depreciation schedules. 

Providing that data as part of the FERC 

Form No. 501–G filing requirement 

would significantly increase the burden 

on the natural gas companies for a form 

with the limited purpose of assisting the 

Commission, the pipelines and the 

parties to screen which pipelines 

deserve additional attention. Similarly, 

permitting parties to challenge or 

protest recalculated ADIT balances and 

amortization amounts on excess and 

deficient ADIT amounts in the section 

1543.404 limited section 4 rate filings 

would undermine the objective of 

expediting rate reductions. 

152. Enable Interstate Pipelines argue 

that, to the extent that significant 

amounts of capital previously available 

to a natural gas company by virtue of 

the ADIT balance are to be removed 

from rate base, the result would be to 

render erroneous any FERC Form No. 

501–G, page 4, estimate of debt cost 

based on access to the ADIT balance, 

given the increasing financial risk and 

hence the cost of capital that would be 

incident to the ADIT change. However, 

Enable Interstate Pipelines appear to 

assume that the ADIT balances have 

been invested in jurisdictional natural 

gas activities. If a natural gas company 

chose to invest funds generated by 

deferred income tax, then its rate base 

would have been increased by a like 

amount,176 and the effect of the ADIT 

adjustment to rate base would be an 

offset. The Commission’s policy to 

adjust rate base stems from the fact that 

tax rules may, in effect, defer payment 

for tax liabilities beyond the timing 

provided for in rates. The pipeline 

collects the customers’ payment while 

obtaining the benefits of the tax 

deferral.177 To reflect the timing 

difference, the Commission requires 

natural gas companies to deduct the 

deferred tax from rate base, with the 

effect that the customers need not pay 

in current rates the time value of the 

money previously paid.178 FERC Form 

No. 501–G reflects Commission policy 

and the § 154.305(c) requirement that 

rate base be adjusted for ADIT balances. 

8. Who Must File 

153. In the NOPR, the Commission 

proposed that ‘‘every natural gas 

company that is required . . . to file a 

Form No. 2 or 2–A for 2017 and has 

cost-based rates for service . . . must 

prepare and file with the Commission a 

FERC Form No. 501–G.’’ 179 The 

Commission also proposed to exempt 

pipelines that, as of the deadline for 

filing their FERC Form No. 501–G, are 

the subject of an ongoing general rate 

case under section 4 or rate 


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180 Id. n.49, proposed 18 CFR 260.402(b)(1)(ii). 

181 Id. PP 4, 26, proposed 18 CFR 

260.402(b)(1)(ii). 

182Hampshire Comments at 3. 

183AGA Comments at 8. 

184 Indicated Shippers Comments at 14–15. 

185Boardwalk Comments at 18; Dominion Energy 

Comments at 14; Kinder Morgan Comments at 29; 

National Fuel Comments at 1–2; Spectra Comments 

at 13; TransCanada Comments at 14; Williams 

Comments at 5. 

186 INGAA Comments at 28; Kinder Morgan 

Comments at 30–31. 

187Cove Point Comments at 2; Dominion Energy 

Comments at 15; Williams Comments at 5–6. 

188 Dominion Energy Comments at 14; INGAA 

Comments at 29; Kinder Morgan Comments at 31; 

National Fuel Comments at 2; Tallgrass Pipelines 

Comments at 15. 

189See, e.g., Boardwalk Comments at 18. 

190 Id. at n.44: 

[T]he Commission ‘‘recognize[s] the role of 

settlements in providing rate certainty,’’ and has 

stated that in deciding whether to exercise its 

discretion to initiate a section 5 proceeding, it 

would ‘‘take into account the parties’ interest in 

maintaining a Settlement.’’ (quoting Nat. Gas 

Pipeline Co. of Am. LLC, 162 FERC ¶ 61,009, at P 

29 (2018)). The Commission has explained that, 

without rate moratoria, ‘‘the utility of settlements 

for resolving cases would be severely jeopardized. 

No settlement could ever be truly final, because the 

rates resulting from the settlement would always be 

subject to reopening based on subsequent 

Commission or Court decisions.’’ See Iroquois Gas 

Transmission Sys. L.P., 69 FERC ¶ 61,165, at p. 

61,631 (1994), reh’g denied, 70 FERC ¶ 61,181 

(1995). The Commission also noted that its decision 

not to order a modification to a settlement was 

‘‘consistent with the principle that approved 

settlements are binding on the parties and should 

not be modified simply because it later appears that 

‘the result is not as good as it ought to have been.’ ’’ 

Id. (quoting Tex. E. Transmission Corp. v. FPC, 306 

F.2d 345, 348 (5th Cir. 1962)). 

See also Kinder Morgan Comments at 30 & n.84. 

191 INGAA Comments at 29; Kinder Morgan 

Comments at 32. 

investigation under NGA section 5.180 In 

addition, the Commission proposed that 

any pipeline that files an uncontested 

pre-packaged settlement of its rates after 

the March 26, 2018 publication of the 

NOPR in the Federal Register and 

before the deadline for their One-time 

Report need not file that report.181

a. Comments 

154. Hampshire notes that it has a 

cost-of-service tariff that provides for 

automatic adjustment for changes in 

income tax rates, and requests that such 

pipelines be exempt from the One-time 

Report.182

155. Numerous other commenters 

weigh in on whether, and under what 

circumstances, filing an uncontested 

settlement should exempt the pipeline 

from the One-time Report. Under the 

NOPR, the Commission would exempt 

any pipeline that filed an uncontested 

rate settlement after the March 26, 2018 

date of the NOPR but before the 

deadline for its One-time Report. CAPP 

supports the proposal as is. NGSA and 

Southern Companies argue for a stricter 

proposal, under which the Commission 

would require further information in 

order to ensure that any settlements 

result in rates that are just and 

reasonable in light of the effects of the 

Tax Cuts and Jobs Act. Similarly, APGA 

argues not only that pipelines under 

settlement moratoria should be subject 

to the One-time Report, but also that the 

Commission should be prepared to 

commence investigations on such 

pipelines prior to the expiration of the 

moratoria, given the inevitable delays 

under NGA section 5 in proceeding 

from an investigation to a final rate.183

Indicated Shippers request that the 

Commission clarify that any pipeline 

precluded from making changes to its 

rates due to a settlement moratorium 

would be required to comply with the 

FERC Form No. 501–G filing 

requirement once the settlement 

moratorium has expired.184

156. Several other commenters 

present overlapping arguments for 

expanding settlement-related 

exemptions. Commenters request 

exemptions from the One-time Report 

for pipelines with rate settlements that 

pre-date the NOPR, but also (1) contain 

a rate moratorium clause; 185 (2) postdate the Tax Cuts and Jobs Act; 186 or (3) 

expressly contemplate future changes to 

tax rates.187 Similarly, commenters 

request a FERC Form No. 501–G 

exemption for pipelines that, whether 

voluntarily or due to a settlement 

comeback clause, elect Option 2, that is, 

to file a new general section 4 rate case 

or settlement shortly after the filing 

deadline for the One-time Report.188

157. For each of these four categories, 

commenters argue that filing the Onetime Report ‘‘would serve no purpose 

. . . since the rates would not be 

affected.’’ 189 Commenters argue that 

filing the One-time Report would cut 

against the Commission’s longstanding 

policy of not disturbing accepted 

settlements.190 In particular, 

commenters argue that filing the FERC 

Form No. 501–G would prejudice the 

pipeline by presenting an incomplete or 

confusing picture of how the tax 

changes affect the pipeline’s rates.191

b. Discussion 

158. The Commission clarifies that 

pipelines such as Hampshire that have 

formula rates which provide for 

automatic rate adjustment to account for 

changes in income tax rates are not 

covered by this rulemaking. 

Accordingly, the Commission is revising 

proposed §§ 154.404(b)(2) and 

260.402(b)(1), to clarify that the 

authorization to file a limited NGA 

section 4 filing and the requirement to 

file a FERC Form No. 501–G only apply 

to natural gas pipelines that have costbased, stated rates. 

159. We decline to adopt commenters’ 

other proposals to expand the proposed 

exemptions from filing the FERC Form 

No. 501–G, and instead adopt the 

proposal in the NOPR, providing an 

automatic exemption from filing FERC 

Form No. 501–G only to (1) pipelines 

who file an uncontested, prepackaged 

settlement of their rates between the 

March 26, 2018 date the NOPR was 

published in the Federal Register and 

the date their FERC Form No. 501–G 

would otherwise be due and (2) 

pipelines whose rates are being 

examined in a general rate case under 

NGA section 4 or a rate investigation 

under NGA section 5 as of the deadline 

for filing their FERC Form No. 501–G. 

However, we clarify that pipelines may, 

on a case-by-case basis, request waivers 

of the filing requirement. 

160. With regard to settlements, the 

Commission finds it appropriate to limit 

the exemption to settlements filed after 

the March 26, 2018 publication of the 

NOPR in the Federal Register. It is only 

in that circumstance, that the 

Commission is willing to presume that 

all the settling parties were aware of, 

and took into account, both the NOPR 

and the United Airlines Issuances 

concerning MLP pipeline tax 

allowances when they agreed to the 

settlement, and therefore no further 

change in the pipeline’s rates is needed. 

However, when a settlement was filed 

before March 26, 2018, the Commission 

will not prejudge what action to take 

with respect to the subject pipeline’s 

rates until interested persons have been 

provided a process in which to state 

their views concerning how the 

settlement should affect the 

Commission’s decision. Based on those 

comments, the Commission can 

determine whether no change in the 

pipeline’s rates is justified at this time 

because (1) the settlement reflects an 

agreement by the parties that the 

pipeline’s revised rates reasonably 

reflect the reduced income taxes 

provided by the Tax Cuts and Jobs Act 

and the United Airlines Issuances and/ 

or (2) any rate moratorium in the 

settlement should be interpreted as 

prohibiting changes to the settlement 

rates to reflect the Tax Cuts and Jobs Act 

and the United Airlines Issuances 

during the term of the rate moratorium. 

161. With regard to rate moratoria, as 

the Commission stated in the NOPR, 

‘‘the Commission generally does not 

disturb a settlement during a rate 


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192NOPR, FERC Stats. & Regs. ¶ 32,725 at P 49 

(citing Iroquois Gas Transmission System L.P., 69 

FERC at 61,631; JMC Power Projects v. Tennessee 

Gas Pipeline Co., 69 FERC ¶ 61,162, reh’g denied, 

70 FERC at 61,528, aff’d, Ocean States Power, 84 

F.3d 1453). See also Natural Gas Pipeline Co., 162 

FERC ¶ 61,009, at P 29 (2018) (stating that in 

deciding whether to initiate an NGA section 5 rate 

investigation, ‘‘the Commission would take into 

account the parties’ interest in maintaining a 

settlement.’’). 

193For administrative efficiency, the Commission 

requires any request for an exemption from filing 

the FERC Form No. 501–G to be filed using the 

same Type of Filing Code as used by the FERC 

Form No. 501–G: ToFC 1430. 

194Although the NOPR preamble clearly limited 

this exemption to situations where pipelines had 

filed a general rate case or prepackaged settlement 

‘‘before the deadline for their One-time Report,’’ 

(NOPR, FERC Stats. & Regs. ¶ 32,725 at P 26) the 

proposed regulatory text in § 260.402(b)(1)(ii) was 

less clear on this point. Accordingly, we are 

revising that section to clearly limit this exemption 

to situations where the relevant filing was made 

before the deadline for the pipeline’s FERC Form 

No. 501–G. Since March 26, 2018, five pipelines 

have made such filings. On May 2, 2018, Granite 

State Gas Transmission, Inc. (Granite State) filed a 

prepackaged uncontested settlement in Docket No. 

RP18–793–000 (approved at Granite State Gas 

Transmission, Inc., 163 FERC ¶ 61,224 (2018)). On 

May 31, 2018, MoGas Pipeline LLC (MoGas) filed 

a general NGA section 4 rate case in Docket No. 

RP18–877–000. On June 29, 2018, Empire Pipeline, 

Inc. (Empire), Enable Mississippi River 

Transmission, LLC (Enable), and Trailblazer 

Pipeline Co. LLC, (Trailblazer) filed general section 

4 rate cases in Docket Nos. RP18–940–000, RP18– 

923–000, an RP18–922–000 respectively. As such, 

Granite State, MoGas, Empire, Enable, and 

Trailblazer are not required to file FERC Form No. 

501–G. 

Additional pipelines may choose to file NGA 

section 4 rate filings before this Final Rule is 

effective; those pipelines would not be required to 

file the FERC Form No. 501–G. Because the 

numbers are dynamic and may continue to change 

(reducing the number of filers of the FERC Form 

No. 501–G), we are retaining a conservative 

estimate of 129 pipelines who may be required to 

file the FERC Form No. 501–G. 

195Eastern Shore Comments at 4 (citing Eastern 

Shore Natural Gas Co., 163 FERC ¶ 61,054 (2018)). 196Eastern Shore Natural Gas Co., 163 FERC 

¶ 61,054 at P 1. 197Eastern Shore Natural Gas Co., 162 FERC 

¶ 61,183 (2017). 198EQT Midstream Comments at 13–14; Tallgrass 

Pipelines Comments at 19–20. 

moratorium.’’ 192 However, this policy 

only extends to rate changes that would 

violate the terms of the rate moratorium 

in the settlement at issue. Some 

settlement rate moratoria include 

exceptions for certain types of rate 

changes, which might include rate 

changes resulting from generic policy 

changes of the type at issue here. 

Accordingly, if a pipeline contends that 

its rates are subject to a rate moratorium, 

the Commission finds it reasonable to 

give other interested persons an 

opportunity to state whether they agree 

that the rate moratorium is applicable to 

the reduced tax costs at issue here. 

162. A pipeline’s filing of the FERC 

Form No. 501–G, together with any 

explanation it wishes to provide of why 

its rate settlement justifies not adjusting 

its rates at this time, will give interested 

persons the requisite opportunity to 

present their views on whether the 

settlement has reasonably modified the 

pipeline’s rates to reflect the Tax Cuts 

and Jobs Act and/or the United Airlines 

Issuances and whether any rate 

moratorium prohibits a rate change at 

this time. However, if an individual 

pipeline believes that the issue of 

whether a pre-March 26, 2018 

settlement justifies not adjusting its 

rates at this time can be resolved 

without the need to file the FERC Form 

No. 501–G, it may file a request for a 

waiver of the requirement to file the 

FERC Form No. 501–G, with an 

explanation of why its pre-March 26, 

2018 settlement justifies no change in 

its rates to reflect the Tax Cuts and Jobs 

Act and/or the United Airlines 

Issuances.193 The pipeline should file 

such a request at least 30 days before the 

date its FERC Form No. 501–G is due. 

Any such request will be noticed for 

interventions, protests, and comments, 

and, based upon all the pleadings, the 

Commission will determine whether to 

grant the waiver. 

163. In the NOPR, the Commission 

proposed to exempt pipelines from 

filing the FERC Form No. 501–G, if they 

file a general NGA section 4 rate case or 

a prepackaged rate settlement before the 

deadline for filing their form.194 The 

Commission rejects the request that this 

automatic exemption be expanded to 

include pipelines that commit to file a 

general section 4 rate case or 

prepackaged settlement within some 

period after the otherwise applicable 

deadline for filing the form. Given the 

Commission’s lack of refund authority 

under NGA section 5, the Commission 

is unwilling to automatically exempt 

pipelines from filing the FERC Form No. 

501–G based on commitments to file 

rate cases or settlements at some time in 

the future. The Commission also rejects 

contentions that providing the 

information required by the FERC Form 

No. 501–G will prejudice settlement 

talks or unduly burden the pipeline. As 

several commenters acknowledge, any 

pipeline hoping to reach a future 

settlement would inevitably grant 

shippers access to even more 

information than the FERC Form No. 

501–G would collect. However, on a 

case-by-case basis, individual pipelines 

may file requests for waiver of filing the 

FERC Form No. 501–G if they are in 

settlement negotiations. In deciding 

whether to grant such waivers, the 

Commission will consider whether 

other interested parties support or do 

not oppose the request. We encourage 

pipelines to file such requests for waiver 

as soon as practicable to allow time for 

the Commission to issue a decision on 

the request. We note that pipelines are 

obligated to meet their FERC Form No. 

501–G filing obligation by the deadline 

outlined in the Implementation Guide 

unless the Commission has issued an 

order affirmatively granting the 

requested waiver on or before that 

deadline. 

164. Eastern Shore argues that it 

should be exempt from filing the Onetime Report because it has already filed 

to lower its rates, in response to a 

settlement provision triggered by the 

Tax Cuts and Jobs Act, and its filing was 

accepted on April 24, 2018.195 However, 

Eastern Shore’s referenced filing was a 

compliance filing made March 1, 

2018,196 pursuant to a rate case 

settlement it filed on December 13, 2017 

that the Commission approved on 

February 28, 2018.197 The December 13, 

2017 settlement was prior to the 

Commission’s issuances of the NOPR 

and United Airlines Issuances. Parties to 

the settlement could not have been 

aware of these Commission orders. As 

discussed above, the Commission will 

not presume what the parties’ positions 

may be with respect to settlements filed 

prior to March 26, 2018. The 

Commission will not exempt Eastern 

Shore from filing a FERC Form No. 501– 

G in this Final Rule. But, as discussed 

above, it may file a separate request for 

a waiver of the FERC Form No. 501–G 

filing requirement which interested 

persons may comment upon. 

165. EQT Midstream and Tallgrass 

Pipelines request that the Commission 

‘‘provide other pipelines with the ability 

to request a waiver,’’ or an extension of 

time, with both citing the example of a 

publicly announced corporate 

restructuring.198 We clarify that 

pipelines have the same right to request 

waiver or an extension of time of the 

One-time Report for any reason as they 

do to request waiver or an extension of 

time of any informational reporting 

requirement. We caution, however, that 

the Commission bears no obligation to 

grant any request that would have the 

effect of delaying rate relief, and as 

stated above, pipelines must file the 

FERC Form No. 501–G by the required 

deadline, unless the Commission has 

affirmatively granted a requested 

waiver. 

9. Miscellaneous Changes to FERC Form 

No. 501–G 

a. Comments and Discussion 

166. Boardwalk and INGAA state line 

34 of page 1 of the proposed FERC Form 


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199 INGAA Comments at 39; Boardwalk 

Comments at 30. 200 Indicated Shippers Comments at 15–17. 201See supra P 144. 

No. 501–G is labeled the ‘‘Indicated Rate 

Reduction’’ and provides the results 

from completing the form. Boardwalk 

and INGAA argue this label is 

misleading, and if not modified, would 

create adverse consequences for 

pipelines. Boardwalk claims line 34 

shows only the potential modification to 

a pipeline’s cost of service due to tax 

policy changes, without regard for 

changes that may occur to a pipeline’s 

billing determinants, discount 

adjustments, and other issues impacting 

recourse rates. INGAA states that the 

FERC Form No. 501–G does not show 

what a pipeline’s rate reduction would 

be if the pipeline were to modify its 

rates in response to the new policies on 

income tax and other factors that would 

be considered in a full review of its 

costs and revenues in an NGA sections 

4 or 5 rate proceeding. To prevent line 

34 from being misleading, Boardwalk 

and INGAA propose that the 

Commission should label it ‘‘Indicated 

Cost of Service Reduction.’’ 199

167. The Commission adopts 

Boardwalk’s and INGAA’s proposal to 

change the label for page 1, line 34 to 

‘‘Indicated Cost of Service Reduction’’ 

in the FERC Form No. 501–G. 

168. Indicated Shippers request the 

following additions, in order to ensure 

that the proposed FERC Form No. 501– 

G provides shippers and the 

Commission with sufficient information 

to determine the level of cost reductions 

due to the Tax Cuts and Jobs Act and 

Revised Policy Statement: 

a. Page 1, Lines 6–10—The 

Commission should include a line for 

storage gas losses recorded in Account 

No. 823, which are not appropriately 

included in a pipeline’s cost of service. 

b. Page 1, Lines 7–9 and 12–13—The 

Commission should provide separate 

lines for gas fuel cost exclusions, 

electric power cost exclusions, and 

miscellaneous fuel costs (such as fuel 

cost exclusions for building heat). 

c. Page 1, Line 15 and Page 3, Lines 

1–6—The Commission should include a 

line item detailing ACA [Annual Charge 

Adjustments] costs, as well as a line for 

exclusion of ACA revenues. These costs 

and revenues are not typically included 

in pipeline costs of service for 

ratemaking purposes, given that ACA 

costs are collected through a surcharge. 

d. Page 1, Line 17—The Commission 

should include a separate line item for 

any negative salvage amounts, as well as 

any amortization of asset retirement 

obligations. 

e. Page 2, Line 13—The Commission 

should add two separate lines to reflect 

the effect on the ADIT balance due to 

changes in the tax rate. One line would 

show the temporary differences between 

book and accelerated depreciation rates, 

and the other line would show 

permanent differences due to the change 

in the tax rates under the Tax Cuts and 

Jobs Act. 

f. Page 2, Lines 13–15—The 

Commission should require pipelines to 

submit footnotes that reflect FERC Form 

No. 2 footnote data referenced on these 

lines. 

g. Page 2, Lines 16–17—The 

Commission should require pipelines to 

specify whether the recourse rates are 

based upon a levelized rate design 

versus a traditional rate design. This 

could be accomplished via a separate 

line that displays the regulatory asset or 

liability associated with the rate 

levelization, if applicable. 

h. Page 3, Lines 1–6—The 

Commission should include a line that 

shows revenues reserved for refunds. 

Page 301 of FERC Form No. 2 requires 

gross revenues and reservations for 

refunds to be reported. Reserved 

revenues have book/tax implications in 

the ADIT amounts. 

i. Page 3, Lines 7–8—The Commission 

should include an option for the 

pipeline to state whether it recovers 

both fuel gas and electric fuel costs 

through its fuel tracking and true-up 

mechanism. 

j. Page 4, Lines 8–10 and Lines 29– 

30—The Commission should require the 

pipeline to provide the time period and 

SEC Form 10K reference supporting the 

parent company capital structure 

claimed, in addition to the Ticker and 

Company Name. 

k. Page 4, Line 13—The Commission 

should include a separate line item 

specifying ‘‘other interest,’’ and the 

pipeline should list only those items 

that are properly included in a cost of 

service. 

l. Page 5, Lines 11–24—The 

Commission should require the pipeline 

to provide the year of the owner data 

provided. There is often a lag in the data 

related to ownership percentages (for 

example, the 2017 data would likely 

only include 2016 ownership 

percentages).200

169. The Commission declines 

Indicated Shippers’ requests, except for 

Items j and l noted above. 

170. Indicated Shippers’ request in 

Item a asks the Commission to include 

a line that shows storage gas losses 

recorded in Account No. 823, which are 

not included in a pipeline’s cost of 

service. Account No. 823 can be 

recorded differently by each pipeline 

and may be included in a pipeline’s cost 

of service. It is not possible to account 

for all the differences between pipelines 

so the Commission declines to include 

a separate line for Account No. 823. 

171. For Items b and d, Indicated 

Shippers request to disaggregate the gas 

exclusions and negative salvage data 

provided on the FERC Form No. 501–G. 

However, this request would not 

provide additional information to 

evaluate the impact of the Tax Cuts and 

Jobs Act and the United Airlines 

Issuances on a pipeline’s cost of service. 

Therefore, the Commission finds this 

request unnecessary and declines 

Indicated Shippers’ request. 

172. For Item c, Indicated Shippers 

state that ACA cost and revenue are not 

typically included in a pipeline cost of 

service for ratemaking purposes. 

Indicated Shippers conflate a cost-ofservice item with cost recovery. ACA 

costs are a recoverable cost-of-service 

item. FERC Form No. 501–G is focused 

on costs, not on revenues. The 

Commission finds that the ACA cost is 

appropriately included in the FERC 

Form No. 501–G data and that there is 

no need to modify the form for ACA 

revenues. Therefore, the Commission 

denies Indicated Shippers’ request. 

173. For Item e, Indicated Shippers 

request that the Commission add two 

lines to reflect changes to the ADIT 

balance due to changes in the tax rate. 

The FERC Form No. 501–G already 

reflects changes in ADIT due to the 

changed tax rate, as the data is brought 

over from the pipeline’s FERC Form 

Nos. 2 and 2–A. As is explained 

elsewhere in this order,201 the 2017 

FERC Form Nos. 2 and 2–A ADIT 

balances are required to be recalculated 

reflecting the Tax Cuts and Jobs Act. 

There is no need to show the level of the 

required adjustment. Indicated 

Shippers’ request is denied. 

174. For Item f, Indicated Shippers 

request that the Commission require 

pipelines to supply any associated 

footnotes that may have been provided 

in FERC Form Nos. 2 and 2–A. The 

Commission finds that there is no need 

to require pipelines to submit footnotes 

when they are already provided in the 

pipeline’s Form No. 2 or 2–A. Any 

interested party may simply reference 

the pipeline’s Form No. 2 or 2–A 

footnotes. 

175. For Item g, Indicated Shippers 

request to disaggregate the data in the 

FERC Form No. 501–G by requiring 

pipelines to specify whether the 

recourse rates are based upon a 

levelized rate design versus a traditional 

rate design by adding a separate line to 


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202Berkshire Hathaway Comments at Ex. A. 

203TransCanada Comments at 16. 

204 18 CFR 154.313. 

205See, e.g., Equitrans, L.P., 109 FERC ¶ 61,214, 

at P 14 (2004). 

206 Id.; Williston Basin Interstate Pipeline Co., 55 

FERC ¶ 61,340 (1991); National Fuel Gas Supply 

Corp., 69 FERC ¶ 61,253 (1994); CNG Transmission 

Corp., 80 FERC ¶ 61,137 (1997), reh’g denied, 81 

FERC ¶ 61,031 (1997). 

207The five steps of rate design are (1) 

determining the pipeline’s cost of service, (2) 

functionalizing the pipeline’s costs among the 

pipeline’s various operations, (3) classifying the 

pipeline’s fixed and variable costs to reservation 

and usage charges of the pipeline’s rates, (4) 

allocating the costs classified as fixed or variable 

among the pipeline’s various rate zones and 

services, and (5) designing per unit rates for each 

service. Pipeline Service Obligations & Revisions to 

Regulations Governing Self-Implementing 

Transportation; & Regulation of Natural Gas 

Pipelines After Partial Wellhead Decontrol, Order 

No. 636, FERC Stats. & Regs. ¶ 30,939 at 30,431, 

order on reh’g, Order No. 636–A, FERC Stats. & 

Regs. ¶ 30,950, order on reh’g, Order No. 636–B, 61 

FERC ¶ 61,272 (1992), order on reh’g, 62 FERC 

¶ 61,007 (1993), aff’d in part and remanded in part 

sub nom. United Distribution Cos. v. FERC, 88 F.3d 

1105 (D.C. Cir. 1996), order on remand, Order No. 

636–C, 78 FERC ¶ 61,186 (1997). 

208Berkshire Hathaway Comments at Ex. A. 

display the regulatory asset balance 

attributable to the levelized rate design. 

The FERC Form No. 501–G already 

carries over the FERC Form Nos. 2 and 

2–A data that includes regulatory assets 

or liabilities attributable to levelized 

rates. Indicated Shippers do not identify 

what purpose would be served by the 

additional level of disaggregation. The 

Commission finds Indicated Shippers’ 

request unnecessary. 

176. Indicated Shippers request in 

Item h to add a line to show revenues 

reserved for refunds. FERC Form No. 

501–G focuses on a pipeline’s cost of 

service. Funds reserved for refunds are 

pipeline revenues. FERC Form No. 

501–G is focused on costs, and not on 

revenues. The Commission rejects 

Indicated Shippers’ proposed change. 

177. For Item i, Indicated Shippers 

request to include an option to state 

whether a pipeline recovers both fuel 

gas and electric fuel costs through its 

fuel tracking and true-up mechanism. 

The Commission is aware that pipelines 

record gas and electric fuel, lost and 

accounted for gas, and related gas sales 

and purchases, in a variety of accounts. 

On page 3, Lines 2–4 capture the major 

accounts. Lines 7 and 8 request 

information as to whether a pipeline has 

a true-up mechanism for fuel or stated 

rates. The Commission acknowledges 

that the FERC Form No. 501–G 

adjustments for fuel and related costs 

will not be complete. However, as the 

major accounts are accounted for, the 

end result should not significantly 

impact the use of the form as a 

screening tool. 

178. For Item k, Indicated Shippers 

request to include a separate page 4 line 

item specifying ‘‘other interest’’ and list 

only those items that are properly 

included in a cost of service. The 

Commission denies this request. This 

request would require a pipeline to 

make a cost allocation determination, 

which would vary by pipeline. As 

previously stated, the purpose of FERC 

Form No. 501–G is to create a screen to 

determine whether additional 

procedures are required. The form is not 

designed to duplicate each and every 

pipeline’s cost-of-service design. 

179. The Commission will incorporate 

Indicated Shippers’ requests for Items j 

and l, wherein they request the 

pipelines to provide references to the 

data provided on FERC Form No. 501– 

G, page 4, capital structure, and page 5, 

ownership data, respectively. For Item j, 

instead of requiring pipelines to provide 

the time period of the SEC Form 10K 

reference in addition to the ticker and 

company name, the Commission will 

add a separate cell in the FERC Form 

No. 501–G where pipelines can provide 

a hyperlink to the referenced SEC Form 

10K. For Item l, the Commission will 

add a separate cell to the FERC Form 

No. 501–G for pipelines to specify the 

year of the owner data provided. 

180. Berkshire Hathaway requests the 

Commission modify the FERC Form No. 

501–G, pages 1–3 to eliminate marketbased costs and revenues. Berkshire 

Hathaway claims during the course of 

traditional rate proceeding, these 

revenues and costs would not be 

included as part of the cost-of-service 

calculation, and therefore, should not be 

part of the FERC Form No. 

501–G reporting.202 TransCanada raises 

similar concerns that the FERC Form 

No. 501–G should exclude all 

incremental cost of service and revenue 

components from FERC Form No. 2 

pages 217 and 217a.203

181. The Commission rejects 

Berkshire Hathaway’s and 

TransCanada’s proposal to exclude costs 

and revenues from the FERC Form Nos. 

2 and 2–A, pages 217 and 217a. 

Contrary to Berkshire Hathaway’s 

claims that the non-traditional cost and 

revenue would not be included in a 

cost-of-service calculation, general rate 

case filings pursuant to Part 154 of the 

Commission’s regulations require 

pipelines to provide a complete cost of 

service, including non-jurisdictional 

functions and costs associated with 

service for which the pipeline does not 

propose to change the rates.204 As the 

Commission has explained, a complete 

cost-of-service filing is required to 

permit examination and allocation of 

common costs.205 A complete cost of 

service would include market-based rate 

and incremental services. Incomplete 

rate case filings may be rejected.206 If, as 

a matter of functionalization, cost 

allocation or rate design,207 a pipeline 

believes that the data in FERC Form No. 

501–G should be adjusted, they may do 

so in an Addendum to the FERC Form 

No. 501–G filing. 

182. In addition, Berkshire Hathaway 

argues that on FERC Form No. 501–G’s 

page 1, lines 7–9 and 12–13, and page 

3, lines 2–5, all revenues and expense 

should be included in the cost of service 

and return on equity calculations; 

therefore, page 1, lines 7–9 and 12–13, 

and page 3, lines 2–5 related to fuel and 

gas balances are not necessary. 

Berkshire Hathaway explains pipelines 

without fuel, unaccounted for gas, or 

other trackers could have potential gains 

or losses associated with the fuel 

revenues collected and sales expenses 

associated with such activity, which 

should flow through the cost of service 

and return on equity calculations as part 

of the FERC Form No. 501–G 

calculation. Berkshire Hathaway states 

excluding these accounts would fail to 

capture those gains and losses. 

Conversely, pipelines with trackers 

should not have any gains or losses on 

fuel or sale expense; therefore, 

including all of these accounts would 

ensure that the net amount is zero. In 

either case, Berkshire Hathaway asserts 

no adjustments are necessary.208

183. The Commission denies 

Berkshire Hathaway’s request. FERC 

Form No. 501–G is designed to create a 

non-gas cost of service. The form is 

designed in this manner as most 

pipelines have some form of fuel tracker 

that should result in cost and revenue 

neutrality. As noted above in discussing 

Indicated Shippers’ Item i, the 

Commission is aware that the listed 

accounts will not capture all the 

accounts that may include fuel and gas 

balance accounts. However, a form 

designed to be used by approximately 

130 pipelines cannot achieve the cost of 

service and rate design granularity to 

accurately reflect every pipeline’s 

individual circumstance. The 

Commission is aware that pipelines 

with stated fuel rates may not have cost 

and revenue neutrality. That is why 

FERC Form No. 501–G, page 3, lines 7– 

8 request information as to whether the 

pipeline’s tariff provides for a fuel 

tracker or stated fuel rates. For pipelines 

with a stated fuel rate, the form is 

consistent in its treatment of that costof-service item as every other cost-ofservice item. Additionally, FERC Form 

No. 501–G, page 3, line 5 requests the 

removal of any other fuel related 


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209Spectra Comments at 28. 

210NOPR, FERC Stats. & Regs. ¶ 32,725 at P 39. 

211 18 CFR 154.312 and 154.313. 

212TransCanada Comments at 16–17. 213NOPR, FERC Stats. & Regs. ¶ 32,725 at P 42. 

revenues from any source that are not 

recognized as part of its non-fuel cost of 

service. 

184. Millennium observes that page 1 

of FERC Form No. 501–G automatically 

assumes an income tax allowance of 

zero for any pass-through entities’ costs 

of service, while page 5 of FERC Form 

No. 501–G reflects an income tax 

allowance for pass-through entities 

calculated pursuant to the 

Commission’s 2005 Policy Statement. 

Accordingly, Millennium asserts that 

the form is internally inconsistent. 

185. The Commission clarifies that 

there is no inconsistency. The 

information requested on page 5 

provides the current income tax 

allowance reflected in the current rates 

of the pipeline prior to the Tax Cuts and 

Jobs Act and the United Airlines 

Issuances. By comparing a cost of 

service containing the income tax 

allowance applicable to current rates 

with a cost of service containing the 

reduced or eliminated income tax 

allowance consistent with 

§ 154.404(a)(2), FERC Form No. 501–G 

determines the Indicated Cost of Service 

Reduction on line 34 of page 1. 

186. Furthermore, the Commission 

clarifies that any pipeline that answers 

‘‘no’’ to the question on line 4 of page 

1 in the FERC Form No. 501–G, ‘‘Is the 

Pipeline a separate income taxpaying 

entity?’’ must answer lines 13–26 of 

page 5 in the FERC Form No. 501–G and 

include the most recent date the 

marginal taxes rates represent. This 

applies whether or not the pipeline 

seeks the limited section 4 filing 

pursuant to § 154.404(a)(2). The 

Commission requests this information 

because it is not available to the public 

and provides useful data for assessing 

the effect of the tax policy changes on 

pipeline cost of service. The 

Commission is adding this guidance to 

both the FERC Form No. 501–G and to 

the FERC Form No. 501–G 

Implementation Guide. 

187. Spectra argues the proposed 

FERC Form No. 501–G is not structured 

appropriately to account for joint 

venture ownership of pipelines. Spectra 

explains that many of the fields in the 

form and the hard-wired formulae and 

outputs from those fields simply do not 

apply to joint ventures. For example, 

Spectra points to page 5 of the form that 

provides a list breaking down equity 

owners but does not reference joint 

ventures. Spectra also argues the FERC 

Form No. 501–G does not address how 

to include an income tax allowance for 

pipelines owned in part by corporations 

and in part by MLP pipelines. Spectra 

asserts the form should be revised to 

clearly address joint venture pipelines 

and allow for inclusion of an income tax 

allowance for these entities, or to allow 

pipelines the opportunity to reflect such 

ownership and appropriate cost-ofservice components in the FERC Form 

No. 501–G.209

188. The Commission will accept in 

part and deny in part Spectra’s request 

to revise the FERC Form No. 501–G. To 

account for each pipeline’s unique 

situation is not feasible and may overly 

complicate the FERC Form No. 501–G. 

Instead, pipelines may make 

adjustments to individual line items in 

additional work sheets attached as an 

Addendum to the FERC Form No. 501– 

G to properly reflect their situation.210

If Spectra or any other pipeline 

proposes any adjustments, it must fully 

explain and support the adjustments in 

the Addendum. All adjustments should 

be provided in a manner similar to that 

required in adjustments to base period 

numbers provided in statements and 

schedules required by § § 154.312 and 

154.313 of the Commission’s 

regulations.211

189. TransCanada notes that as 

proposed, FERC Form No. 501–G 

requires pipelines to input the cost of 

capital from FERC Form No. 2 page 218a 

to complete lines 3 through 5. 

TransCanada argues this data is 

inappropriate to determine a pipeline’s 

capital structure, as that data is used for 

calculating AFUDC, and as a result, it 

includes prior year-end balances.212 The 

Commission acknowledges that in 

certain situations, this may result in 

slightly out-of-date capital structures. 

This timing problem should be 

ameliorated by the revision of page 4 of 

FERC Form No. 501–G to re-rank the 

capital structure analysis. In the event 

that any responses on the One-time 

Report nevertheless reflect inaccurate 

capital data, we encourage respondents 

to explain the inaccuracy in an 

Addendum to their report. 

C. Additional Filing Options for Natural 

Gas Companies 

190. In the NOPR, the Commission 

proposed that, upon filing of the FERC 

Form No. 501–G, interstate natural gas 

pipelines would have four options. The 

first two options—filing a limited NGA 

section 4 rate filing or a general NGA 

section 4 rate case—would allow the 

pipelines to voluntarily make a filing to 

address the effects of the Tax Cuts and 

Jobs Act and the Revised Policy 

Statement. Under the third option, 

pipelines could file an explanation why 

no rate change is necessary. Finally, 

pipelines could file the FERC Form No. 

501–G described above, without taking 

any other action at this time. As 

discussed below, in this Final Rule, the 

Commission adopts all four of these 

options, with various clarifications. 

1. Limited NGA Section 4 Filing 

(Option 1) 

a. NOPR 

191. The Commission proposed that, 

together with its FERC Form No. 

501–G, an interstate natural gas pipeline 

could file a limited NGA section 4 filing 

to allow interstate pipelines to reduce 

their rates to reflect the reduced income 

tax rates and elimination of the MLP 

pipeline income tax allowance on a 

single-issue basis, without consideration 

of any other cost or revenue changes. In 

other words, the Commission proposed 

to allow interstate natural gas pipelines 

to file a limited NGA section 4 filing, 

pursuant to proposed § 154.404, to 

reduce their reservation charges and any 

one-part rates that include fixed costs by 

the percentage reduction in their costs 

of service calculated in the FERC Form 

No. 501–G resulting from the reduced 

corporate income tax rates provided by 

the Tax Cuts and Jobs Act and the 

elimination of MLP tax allowances by 

the Revised Policy Statement. The 

Commission proposed to require MLP 

pipelines to eliminate their income tax 

allowances in any limited NGA section 

4 filing, but permitted other passthrough entities to either eliminate their 

income tax allowances or justify why 

they should continue to receive an 

income tax allowance and to reduce 

their rates to reflect the decrease in 

federal income tax rates applicable to 

partners pursuant to the Tax Cuts and 

Jobs Act. The Commission stated that 

interested parties may protest the 

limited NGA section 4 filing, but that 

the Commission would only consider 

arguments relating to matters within the 

scope of the proceeding.213

192. The Commission noted that it 

generally does not permit pipelines to 

change any single component of their 

cost of service outside of a general NGA 

section 4 rate case but that the 

Commission believes an exception to 

that policy is justified in this case in 

order to permit interstate pipelines to 

voluntarily reduce their rates as soon as 

possible to reflect a reduction in a single 

cost component—their federal income 

tax costs—so as to flow through that 

benefit to consumers. The Commission 

also noted that the proposed 

requirement that all interstate pipelines 


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214 Id. P 44. 

215 INGAA Comments at 29; Dominion Energy 

Comments at 11; Williams Comments at 8; EQT 

Midstream Comments at 12–13; Kinder Morgan 

Comments at 33. 

216 INGAA Comments at 29. 

217 Id.; Williams Comments at 8; EQT Midstream 

Comments at 12–13; Kinder Morgan Comments at 

33. 

218 INGAA Comments at 30; Kinder Morgan 

Comments at 33. 

219 INGAA Comments at 30 (citing NOPR, FERC 

Stats. & Regs. ¶ 32,725 at P 42). 

220 Id. 

221EQT Midstream Comments at 18–19; Tallgrass 

Pipelines Comments at 22. 

222APGA Comments at 7 (noting that proposed 

§ 154.404(c) permits the pipeline to reduce only its 

reservation rates). 

223APGA Comments at 4–5. 

224FERC Form No. 501–G includes a new column 

titled ‘‘Rate Moratorium Option 12% ROE Test.’’ In 

that column, the effect of a limited section 4 rate 

reduction is measured by reducing a pipeline’s total 

adjusted revenues (adjusted for non-base rate and 

non-jurisdictional activities) by the indicated costof-service reduction. The Commission is aware this 

adjustment is a proxy for a detailed revision to rates 

and does not reflect any discount adjustment, 

negotiated rates or treatment of fixed and variable 

cost components. With that caveat, the ROE 

calculation for the three-year rate moratorium 

begins with the adjusted revenue and subtracts the 

operating costs to obtain revised income before 

income taxes. That amount is further reduced to 

reflect the new tax rates for a C Corp or elimination 

thereof for a pass-through entity to calculate net 

income. The net income is compared to the 

pipeline’s rate base to develop the test ROE to 

determine whether the pipeline qualifies for the 

moratorium. 

225See General Motors Corp v. FERC, 613 F.2d at 

944 (‘‘[A]n administrative agency’s decision to 

conduct or not to conduct an investigation is 

committed to the agency’s discretion.’’) (citations 

omitted). 

file the abbreviated cost and revenue 

study in FERC Form No. 501–G would 

enable pipelines and all other interested 

parties to evaluate whether there are 

significant changes in other cost 

components or revenues that affect the 

need for a rate reduction with respect to 

taxes.214

b. Comments 

193. Several commenters argue that 

the Commission should impose a 

moratorium on NGA section 5 actions if 

a pipeline chooses to make the limited 

NGA section 4 filing.215 INGAA argues 

that pipelines electing to make the 

limited NGA section 4 filing will be 

implementing a rate decrease sooner 

than would be required in a section 5 

rate proceeding and that pipelines will 

have no incentive to make the limited 

NGA section 4 filing absent a firm 

assurance that it will not immediately 

be subject to an additional NGA section 

5 proceeding.216 Some commenters 

suggest a moratorium of at least three 

years would be appropriate.217

194. INGAA and Kinder Morgan argue 

that a pipeline that elects to file a 

limited section 4 rate case should not be 

required to complete page 3 of FERC 

Form No. 501–G, which collects the 

data necessary to calculate an estimated 

ROE.218 INGAA argues that the 

Commission stated that it will only 

consider protests of the limited NGA 

section 4 filings that are directly related 

to the reduced income tax rates and 

elimination of the MLP pipeline income 

tax allowances.219 INGAA contends that 

this information serves no purpose, 

would not lead to additional rate 

modifications under the limited NGA 

section 4 option, and the information 

could be used as a basis for a complaint 

by shippers seeking to initiate a section 

5 proceeding.220

195. Commenters ask for clarification 

regarding whether a pipeline is limited 

to using the data provided in the FERC 

Form No. 501–G without adjustment 

when reducing its rates under the 

limited NGA section 4 option or 

whether a pipeline is permitted to 

incorporate into its calculations the 

supported adjustments included in the 

Addendum that are permitted under the 

NOPR.221

196. APGA contends that not all 

interstate natural gas pipelines employ 

a straight fixed-variable rate design 

where all fixed costs are collected 

through the reservation charge and that 

the Commission should allow a pipeline 

to revise usage rates as well if there are 

fixed costs collected in usage rates.222

197. APGA asks the Commission to 

clarify that a limited NGA section 4 rate 

filing (to reduce a pipeline’s reservation 

charges and any one-part rates that 

include fixed costs by the percentage 

reduction in its cost of service 

calculated in the FERC Form No. 

501–G) may be made prior to the due 

date for FERC Form No. 501–G.223

c. Discussion 

198. The Commission adopts 

proposed § 154.404 authorizing natural 

gas pipelines to submit limited NGA 

section 4 filings to reduce their rates to 

reflect the Tax Cuts and Jobs Act and 

the United Airlines Issuances, with 

three modifications. First, as already 

discussed, the Commission is removing 

the requirement that MLP pipelines 

eliminate their tax allowances in any 

limited NGA section 4 filing. Instead, 

like other pass-through entities, MLP 

pipelines may either eliminate their tax 

allowances or reduce their rates to 

reflect the reduced income tax expenses 

provided by the Tax Cuts and Jobs Act. 

Second, as discussed below, we grant in 

part commenters’ request for a 

moratorium on NGA section 5 

investigations in the event a pipeline 

chooses the limited NGA section 4 

option. Third, as discussed below, the 

Commission is also revising proposed 

§ 154.404 to recognize that pipelines 

that do not use a straight fixed-variable 

rate design may include fixed costs in 

their usage charges and thus require that 

such pipelines’ limited NGA section 4 

filings include a percentage reduction of 

any usage charges including fixed costs. 

199. We grant, in part, commenters’ 

request for a moratorium on NGA 

section 5 investigations in the event a 

pipeline chooses to make a limited NGA 

section 4 rate reduction filing. Such a 

filing is an efficient and expeditious 

method of passing along to ratepayers 

the benefit of the reduction in the 

corporate income tax rate or the 

elimination of the MLP income tax 

allowance, without the need for the 

costly and time-consuming litigation 

entailed in an NGA section 5 rate 

investigation. Accordingly, it is 

reasonable to provide pipelines an 

incentive to make such limited NGA 

section 4 rate reduction filings. On the 

other hand, it is possible that a pipeline 

could make a limited NGA section 4 rate 

reduction filing and yet still have a 

significantly excessive ROE. In order to 

balance these concerns, the Commission 

has determined that it will not initiate 

an NGA section 5 investigation into the 

rates of a pipeline for three years from 

the effective date of the rate reduction 

resulting from the pipeline’s limited 

NGA section 4 filing if the pipeline’s 

filing meets certain requirements. A 

pipeline would qualify for the NGA 

section 5 investigation moratorium if (1) 

the Commission accepts its limited NGA 

section 4 filing and (2) its Total 

Estimated ROE after the filing, as 

calculated on page 3, line 26, column 

(E) of its FERC Form No. 501–G, is 12 

percent or less.224 For purposes of 

determining whether a pipeline 

qualifies for the NGA section 5 

investigation moratorium, the 

Commission will rely on data in the 

FERC Form No. 501–G itself, without 

considering any adjustments the 

pipeline may include in an Addendum, 

so as to minimize any disputes as to 

whether the pipeline qualifies for the 

moratorium. However, as discussed 

below, the pipeline is free to calculate 

the percentage rate reduction proposed 

in its limited NGA section 4 filing using 

the adjusted data in its Addendum to its 

FERC Form No. 501–G. 

200. The Commission uses its 

discretion when deciding whether to 

initiate an NGA section 5 

investigation.225 Using a 12 percent 

Total Estimated ROE threshold to 

determine whether a pipeline qualifies 

for a moratorium will allow for a more 


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226See NOPR, FERC Stats. & Regs. ¶ 32,725 at 

P 42. 

227 Id. P 47. 

228 Id. 

229 INGAA Comments at 23–25; Dominion 

Comments at 12–14; Southern Star Comments at 10; 

EQT Midstream Comments at 9–12; Tallgrass 

Pipelines Comments at 13–15; Kinder Morgan 

Comments at 34–35; Spectra Comments at 9. 

230Tallgrass Pipelines Comments at 15. 

231EQT Midstream Comments at 10. 

efficient use of the Commission’s 

resources and provide an additional 

incentive for pipelines to choose the 

limited NGA section 4 filing option so 

that customers will receive a rate 

reduction sooner than if the 

Commission initiated an NGA section 5 

investigation. 

201. The Total Estimated ROE 

calculated in the FERC Form No. 

501–G need not be 12 percent or less for 

the Commission to accept a limited 

NGA section 4 filing. Further, a FERC 

Form No. 501–G with a Total Estimated 

ROE higher than 12 percent will not 

necessarily result in a NGA section 5 

rate investigation. For pipelines that are 

not covered by the moratorium, the 

Commission will take many factors into 

consideration when determining 

whether to exercise its discretion to 

initiate a NGA section 5 investigation, 

including whether a pipeline chooses 

the limited NGA section 4 option, any 

information the pipeline provides in an 

Addendum to its FERC Form No. 

501–G, or any other explanation the 

pipeline may provide as to why the 

Commission should not initiate a NGA 

section 5 rate investigation. Finally, we 

note that the NGA section 5 

investigation moratorium would not 

prevent customers from filing an NGA 

section 5 complaint. 

202. We agree with APGA that not all 

interstate natural gas pipelines employ 

a straight fixed-variable rate design 

where all fixed costs are collected 

through the reservation charge and that 

a pipeline should be able to revise usage 

rates using the limited NGA section 4 

option if there are fixed costs collected 

in usage rates. Accordingly, we have 

revised proposed § 154.404 to require 

that the authorized limited NGA section 

4 filing include a percentage reduction 

of a usage charge that includes fixed 

costs. 

203. We also affirm that pipelines 

must complete FERC Form No. 501–G in 

its entirety, including page 3, even 

when choosing the limited NGA section 

4 filing option. Page 3 of the report 

requires the pipeline to report its 

revenues from which the cost-of-service 

items, as detailed on page 1, are 

subtracted. Thus, the information 

reported on page 3 of the report is 

necessary to calculate the pipeline’s 

ROE before and after the reduction in 

income taxes provided by the Tax Cuts 

and Jobs Act and the elimination of the 

MLP pipeline income tax allowance by 

the United Airlines Issuances. Although 

such ROE information may not be 

relevant to calculating the rate reduction 

included in a limited NGA section 4 rate 

filing, it is relevant to determining 

whether the Commission should initiate 

an investigation of the pipeline’s rates 

under NGA section 5 despite the 

pipeline’s limited NGA section 4 filing, 

and that information is necessary for 

purposes of applying the moratorium 

discussed above. Thus, the pipeline 

must complete the entire FERC Form 

No. 501–G regardless of the subsequent 

filing option chosen by the pipeline. 

204. In response to questions 

regarding whether a pipeline may 

calculate the percentage reduction in its 

rates for the limited NGA section 4 

option using the adjustments in its 

Addendum to the FERC Form No. 501– 

G, we clarify that such adjustments may 

be reflected in the calculation of the 

limited NGA section 4 rate reduction, 

subject to the following conditions. As 

stated in the NOPR, the limited NGA 

section 4 option is meant to ‘‘allow 

interstate pipelines to reduce their rates 

to reflect the reduced income tax rates 

and elimination of the MLP pipeline 

income tax allowance on a single-issue 

basis, without consideration of any 

other cost or revenue changes.’’ 226

Thus, the pipeline may not offset the 

percentage reduction in its cost of 

service resulting from the Tax Cuts and 

Jobs Act and the United Airlines 

Issuances with unrelated increases in its 

cost of service. However, the pipeline 

may take into account adjustments 

included in its Addendum to the FERC 

Form No. 501–G for the purpose of 

accurately calculating the percentage 

reduction in its cost of service caused by 

the Tax Cuts and Jobs Act or the United 

Airlines Issuances. For this purpose, in 

calculating the percentage reduction in 

its cost of service related to the 

reduction or elimination of its tax 

allowance, the pipeline should include 

the cost-of-service adjustments in its 

Addendum in its cost of service for the 

periods both before and after the Tax 

Cuts and Jobs Act and United Airlines 

Issuances. As noted above, for purposes 

of the NGA section 5 investigation 

moratorium, the Commission will use 

the pipeline’s unaltered FERC Form No. 

501–G to determine whether it qualifies 

for the moratorium. 

205. In response to APGA’s request, 

we clarify that a pipeline may file its 

FERC Form No. 501–G and limited NGA 

section 4 filing in advance of the due 

date of its FERC Form No. 501–G, and 

encourage pipelines to do so. A pipeline 

cannot, however, make the limited NGA 

section 4 filing described in this Final 

Rule without also filing the FERC Form 

No. 501–G. 

2. General NGA Section 4 Filing or 

Prepackaged Uncontested Settlement 

(Option 2) 

a. NOPR 

206. The Commission proposed in the 

NOPR that an interstate natural gas 

pipeline could include with its FERC 

Form No. 501–G a commitment to file 

either a prepackaged uncontested 

settlement or, if that is not possible, a 

general NGA section 4 rate case to revise 

its rates based upon current cost data.227

The Commission stated that a pipeline 

choosing this option would also 

indicate an approximate time frame 

regarding when it would file the 

settlement or the NGA section 4 filing. 

The Commission also proposed that if 

the pipeline commits to make such a 

filing by December 31, 2018, the 

Commission would not initiate an NGA 

section 5 investigation of its rates prior 

to that date.228

b. Comments 

207. Several commenters argue that 

pipelines that elect to file a prepackaged settlement or general NGA 

section 4 rate case should be granted 

additional time to make such a filing.229

INGAA argues that the proposed 

deadline of December 31, 2018 does not 

give pipelines sufficient time after the 

filing of FERC Form No. 501–G to 

negotiate uncontested rate settlements, 

and, if such negotiations do not 

succeed, to prepare a general NGA 

section 4 rate case. Tallgrass Pipelines 

contend that the December 31, 2018 

deadline is unduly burdensome, 

especially for companies that own and 

operate multiple jurisdictional natural 

gas pipelines and shippers that ship on 

multiple pipelines.230 EQT Midstream 

contends that a pipeline’s deadline to 

submit its FERC Form No. 501–G is 

directly tied to the date when a Final 

Rule is issued and that a pipeline may 

only have a matter of months to file an 

uncontested settlement agreement or a 

general NGA section 4 rate case with the 

proposed static deadline of December 

31, 2018.231 INGAA argues that the 

proposed deadline discourages 

uncontested settlements because a 

pipeline may not want to allocate its 

limited resources to negotiations and 

instead use those resources to prepare a 


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232 INGAA Comments at 23–25. 233 Dominion Energy Comments at 13. 234 INGAA Comments at 25; Dominion Energy 

Comments at 13; EQT Midstream Comments at 11– 

12; Tallgrass Pipelines Comments at 14; Kinder 

Morgan Comments at 34–35. 

235EQT Midstream Comments at 11. 

236Spectra Comments at 9. 

237EQT Midstream Comments at 19; Dominion 

Energy Comments at 11–12; Tallgrass Pipelines 

Comments at 22–23. 

238EQT Midstream Comments at 19; Tallgrass 

Pipelines Comments at 22–23. 

239 Dominion Energy Comments at 12. 

240EQT Midstream Comments at 19; Tallgrass 

Pipelines Comments at 23. 

241EQT Midstream Comments at 19 (citing NOPR, 

FERC Stats. & Regs. ¶ 32,725 at P 15). 

242 Id. 

243 18 CFR 385.602(h)(1)(i); see also Mobil Oil 

Corp. v. FPC, 417 U.S. 283, 314 (1974). 

general NGA section 4 rate case.232

Dominion Energy argues that shippers 

are unlikely to be ready to negotiate 

until a pipeline’s FERC Form No. 501– 

G has been submitted.233 Commenters 

argue that, instead of imposing a fixed 

December 31, 2018 filing deadline upon 

all pipelines that elect option 2, the 

Commission should allow pipelines to 

file pre-packaged uncontested 

settlements or general NGA section 4 

rate cases up to 180 days following their 

deadline for filing FERC Form No. 501– 

G, and that the Commission should also 

permit parties to request waivers or 

extensions of the filing deadline for prepackaged uncontested settlements or 

rate cases if publically-announced 

settlement discussions are underway 

but parties have not yet resolved all 

issues.234 EQT Midstream argues that 

the Commission should provide 

pipelines additional time to commit to 

filing a general NGA section 4 rate case 

if pipelines choose to engage in 

publicly-noticed prefiling settlement 

negotiations with shippers but fail to 

reach an agreement by December 31, 

2018.235

208. Spectra asks for clarification 

regarding the December 31, 2018 

deadline and whether that is the date 

pipelines should notify the Commission 

whether they will file a pre-packaged 

settlement/general NGA section 4 rate 

case or whether that is the date 

pipelines must make those filings.236

209. Several commenters argue that 

the Commission should not require 

prepackaged settlements to be 

uncontested.237 EQT Midstream and 

Tallgrass Pipelines contend that 

prepackaged settlements submitted 

pursuant to option 2 should be reviewed 

under the Commission’s normal 

standard for reviewing contested 

settlement filings and that prepackaged 

settlements should not be automatically 

rejected because they are not 

uncontested at the time the agreement is 

filed with the Commission.238 Dominion 

Energy argues that requiring 

prepackaged settlements to be 

completely uncontested is too high a bar 

and will likely cause few pipelines and 

customers to attempt that option.239

210. Commenters also argue that the 

Commission should not allow shippers 

with negotiated rates to withhold 

consent from an otherwise uncontested 

prepackaged settlement.240 EQT 

Midstream argues that, given that 

negotiated rate shippers are not 

impacted by a reduction to a pipeline’s 

recourse rate through an NGA section 4 

or 5 filing,241 the Commission should 

clarify that shippers do not have the 

ability to veto an otherwise unopposed 

settlement.242

c. Discussion 

211. In the NOPR, the Commission 

stated that, if a pipeline commits to file 

an uncontested prepackaged settlement 

or a general NGA section 4 rate case on 

or before December 31, 2018, the 

Commission would not initiate an NGA 

section 5 rate investigation before that 

date. In other words, the Commission 

proposed to grant all pipelines who 

make the above described commitment 

a guaranteed safe harbor from an NGA 

section 5 rate investigation until 

December 31, 2018. A number of 

pipeline commenters request that the 

Commission extend this guaranteed safe 

harbor from the initiation of an NGA 

section 5 rate investigation until a later 

date in order to give them more time to 

negotiate settlements with their 

customers and others. 

212. We deny this request. We 

recognize that pipelines must expend 

time and resources to reach a settlement 

or prepare an NGA section 4 rate case, 

but it is important to implement rate 

reductions as a result of the Tax Cuts 

and Jobs Act and the United Airlines 

Issuances. The proposed December 31, 

2018 end of the guaranteed safe harbor 

is already one year after the effective 

date of the Tax Cuts and Jobs Act. We 

also note that pipelines need not wait 

until the FERC Form No. 501–G 

deadline to begin discussions with 

customers or to begin preparing a 

general NGA section 4 rate case. Indeed, 

the Commission encourages pipelines to 

begin discussions with their customers 

immediately, if those discussions have 

not already begun. 

213. However, we clarify that, if a 

pipeline is engaged in productive 

settlement negotiations as the December 

31, 2018 end of the safe harbor period 

approaches, it may file a request for an 

extension of the safe harbor period. The 

filing of such requests will give other 

interested parties an opportunity to state 

whether they agree that productive 

settlement negotiations are underway. 

In determining whether to grant an 

extension, the Commission will 

consider whether other interested 

parties support the request. 

214. Commenters argue that the 

Commission should not require 

prepackaged settlements to be 

uncontested. The Commission notes 

that prepackaged rate change filings 

typically do not contain all the 

supporting documents as required by 

§ 154.312 of the Commission’s 

regulations. As such, there is likely no 

record evidence upon which the 

Commission can approve a prepackaged 

settlement over the objections of a 

protesting party. Although prepackaged 

tariff filings are not technically 

settlements filed pursuant to § 385.602 

of the Commission’s regulations, the 

Commission typically applies Rule 602 

standards in evaluating these filings. 

Under Rule 602 the Commission ‘‘may 

decide the merits of the contested 

settlement issues, if the record contains 

substantial evidence upon which to base 

a reasoned decision. . . .’’ 243 Without 

substantial evidence upon which to base 

a reasoned decision, and without 

additional procedures, the Commission 

could not approve a protested 

prepackaged filing. 

215. In regards to arguments that the 

Commission should not allow shippers 

with negotiated rates to withhold 

consent from an otherwise uncontested 

prepackaged settlement, we determine 

that the effect of opposition by a 

negotiated rate customer can be 

considered on a case-by-case basis. 

3. Statement That No Adjustment in 

Rates Needed (Option 3) 

a. NOPR 

216. In the NOPR, the Commission 

proposed that a pipeline could include 

with its FERC Form No. 501–G a 

statement explaining why no 

adjustment in its rates is needed. The 

Commission recognized that a rate 

reduction may not be justified for a 

significant number of pipelines for a 

number of reasons. For example, a 

number of pipelines may currently have 

rates that do not fully recover their 

overall cost of service. Therefore, a 

reduction in those pipelines’ tax costs 

may not cause their rates to be 

excessive. The Commission stated that 

the proposed FERC Form No. 501–G 

would provide information as to 

whether an interstate pipeline may fall 

into this category. The Commission 

stated that the pipeline could provide a 


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244NOPR, FERC Stats. & Regs. ¶ 32,725 at PP¶ 

49–50. 245 Indicated Shippers Comments at 14–15. 246LDC Coalition Comments at 19–21. 247 Id. at 21. 

248 Direct Energy Comments at 4–5, 8; Range 

Comments at 11–13. 

249 Direct Energy Comments at 8. 

250See NOPR, FERC Stats. & Regs. ¶ 32,725 at P 

28. 

251 Id. P 32. 

full explanation of why, after 

accounting for its reduction in tax costs, 

its rates do not over recover its overall 

cost of service and therefore no rate 

reduction is justified. The pipeline 

would provide this statement along with 

any additional supporting information it 

deems necessary. 

217. The Commission also stated that 

an interstate pipeline might explain that 

an existing rate settlement provides for 

a moratorium on rate changes that 

applies to any rate changes that might 

result from the Tax Cuts and Jobs Act or 

the United Airlines Issuances. The 

Commission stated that interested 

parties would have an opportunity to 

comment on any assertion by a pipeline 

that no adjustment to its rates is needed, 

and the Commission would then 

determine whether further action is 

needed with respect to that pipeline.244

b. Comments 

218. Indicated Shippers argue that the 

Commission should thoroughly examine 

any assertion by a pipeline that its rate 

case settlement includes a rate 

moratorium preventing any rate change 

to reflect the reduction in its tax 

expenses. Indicated Shippers assert that 

some settlements state that the rate 

moratorium does not apply to industrywide Commission mandated changes to 

rates to account for tax cost savings, and 

the Commission should require those 

pipelines to implement rate changes to 

take into account the effects of the tax 

changes.245

219. Indicated Shippers also request 

that the Commission clarify that any 

pipeline that is precluded from making 

rate changes due to a settlement 

moratorium will be required to comply 

with the FERC Form No. 501–G filing 

requirement once the moratorium has 

expired. LDC Coalition similarly argues 

that the Commission should clarify how 

it will encourage pipelines with rate 

case filing moratoria but no requirement 

to file a new rate case after the 

moratorium expires to reflect the impact 

of the Tax Cuts and Jobs Act and the 

Revised Policy Statement on its rates.246

220. LDC Coalition asks the 

Commission to specify how soon a 

pipeline must file a general NGA section 

4 rate case in the context of pipelines 

filing an explanatory statement using a 

comeback provision as justification for 

why an adjustment to its rates is not 

needed.247

221. Direct Energy and Range argue 

that the Commission should establish a 

process for requiring immediate rate 

reductions to reflect the reduction in the 

corporate tax rate or tax allowance 

pursuant to NGA section 5.248 Direct 

Energy argues that the Commission 

should order an immediate proportional 

rate reduction under NGA section 5 for 

pipelines with revenues so far in excess 

of their actual cost of service that the 

rates are presumptively unjust and 

unreasonable under NGA section 5 

based on a review of the information 

provided in the FERC Form No. 

501–G.249

c. Discussion 

222. As explained in the NOPR, 

despite the reduction in the corporate 

income tax and the change in policy 

concerning MLP tax allowances, a rate 

reduction may not be justified for a 

significant number of pipelines. For 

example, the pipeline’s existing rates 

may not fully recover its cost of service 

or a rate moratorium may prohibit rate 

changes at this time. Pipelines may 

include with their filing of the FERC 

Form No. 501–G a statement explaining 

why these or other reasons justify their 

not changing their rates at this time. 

223. As discussed previously, the 

Commission will notice the filing of 

each pipeline’s FERC Form No. 501–G 

and permit interested persons to file 

interventions, protests, and comments. 

If any person disagrees with a pipeline’s 

explanation of why it believes no rate 

change is justified at this time, that 

person may intervene and protest the 

pipeline’s filing. For example, if a party 

that believes that a rate case moratorium 

relied on by the pipeline should be 

interpreted as permitting rate changes 

related to the Tax Cuts and Jobs Act and 

the change in policy concerning MLP 

tax allowances, that party may provide 

a full explanation of why it interprets 

the settlement as it does, and the 

Commission will consider the views of 

both the pipeline and other intervening 

parties in deciding what action to take 

with respect to that pipeline. 

224. Indicated Shippers request that 

the Commission clarify that any 

pipeline precluded from making 

changes to its rates by a settlement 

moratorium will be required to file a 

FERC Form No. 501–G after the 

settlement moratorium. LDC Coalition 

also suggests that the Commission might 

continue the FERC Form No. 501–G 

process beyond the one-time aspect of 

the proposed requirement for any 

pipeline with a settlement rate 

moratorium that extends past the 

compliance filing dates. The 

Commission rejects these requests. The 

Commission is adopting the FERC Form 

No. 501–G process as a one-time filing 

requirement enabling the Commission 

to consider what actions to take to 

address the rate effects of the Tax Cuts 

and Jobs Act. All pipelines with costbased, stated rates are required to make 

their filings by the deadlines established 

in the Implementation Guide. Pipelines 

with rate moratoria currently in effect 

must comply with their applicable 

deadline and may include an 

explanation of why their settlement 

moratorium prevents a rate change at 

this time. If the Commission agrees that 

a rate moratorium prevents a rate 

change at this time, there is no need to 

require the subject pipeline to file 

another FERC Form No. 501–G at such 

time as the rate moratorium expires. The 

Commission intends to continue its 

existing practice of reviewing pipeline 

FERC Form No. 2 and 2–A filings every 

year to determine whether to initiate 

rate investigations under NGA section 5. 

Therefore, when a pipeline’s rate 

moratorium expires, the Commission 

will examine that pipeline’s most recent 

FERC Form No. 2 and 2–A filings as of 

that date and all other relevant factors 

in order to determine whether an NGA 

section 5 investigation of that pipeline’s 

rates is justified. 

225. In response to arguments by 

commenters that the Commission 

should immediately reduce pipelines’ 

rates pursuant to NGA section 5, as 

explained in the NOPR, the Commission 

recognizes that some pipelines need not 

change their rates at this time 250 and, 

therefore, an immediate reduction in all 

pipeline rates pursuant to NGA section 

5 would not be appropriate. We also 

reject the request to immediately reduce 

rates based on a review of the 

information provided in the FERC Form 

No. 501–G. The FERC Form No. 501–G 

is only designed to estimate the 

percentage reduction in the pipeline’s 

cost of service resulting from the Tax 

Cuts and Jobs Act and the United 

Airlines Issuances and the pipeline’s 

current ROEs before and after the 

reduction in corporate income taxes 

and, if applicable, income tax 

allowance.251 However, as discussed 

above, FERC Form No. 501–G cannot 

capture all the intricacies of a fully 

developed cost of service, allocation and 

rate design for all pipelines. The FERC 

Form No. 501–G does not provide 

enough information by itself for the 

Commission to determine the just and 


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252 Indicated Shipper Comments at 13; NGSA 

Comments at 6; Southern Companies Comments at 

5; Direct Energy Comments at 8–9. 

253Southern Companies Comments at 5. 

254 Indicated Shippers Comments at 13. 

255NGSA Comments at 6. 

256NOPR, FERC Stats. & Regs. ¶ 32,725 at P 51 

& n.71 (citing Pub. Serv. Comm. of New York v. 

FERC, 866 F.2d 487, 492 (D.C. Cir. 1989)). 

257NOPR, FERC Stats. & Regs. ¶ 32,725 at P 14 

(citing Negotiated Rate Policy Statement, 104 FERC 

¶ 61,134, order on reh’g and clarification, 114 FERC 

¶ 61,042, dismissing reh’g and denying 

clarification, 114 FERC ¶ 61,304). 

258 Id. P 15. 

259 Id. P 45 (citing Columbia Gulf Transmission 

Co., 109 FERC ¶ 61,152, at P 13, reh’g denied, 111 

FERC ¶ 61,338 (2005)). See also Iberdrola 

Renewables, Inc. v. FERC, 597 F.3d 1299, 1305 (D.C. 

Cir. 2010). 

260NOPR, FERC Stats. & Regs. ¶ 32,725 at P 45. 

261Boardwalk Comments at 17 (citing Columbia 

Gulf Transmission Co., 109 FERC ¶ 61,152 at P 13 

(‘‘To the extent a pipeline and its shipper want to 

obtain rate certainty by agreeing to a rate that will 

remain in effect throughout the term of the service 

agreement, the Commission provides them an 

opportunity to do so by entering into a negotiated 

rate agreement.’’), reh’g denied, 111 FERC ¶ 61,338, 

aff’d, Columbia Gulf Transmission Co. v. FERC, 477 

F.3d 739 (D.C. Cir. 2007)). 

262Boardwalk Comments at 16 (citing Dominion 

Transmission v. FERC, 533 F.3d 845, 852–53 (D.C. 

Cir. 2008) (citing United Gas Pipe Line Co. v. Mobile 

Gas Serv. Corp., 350 U.S. 332 (1956); FPC v. Sierra 

Pac. Power Co., 350 U.S. 348 (1956) (MobileSierra))). 

263 Id. (citing Dominion Transmission, 533 F.3d at 

853 (internal punctuation and citations omitted)). 

264 Id. 

265 Indicated Shippers Comments at 6 (citing 

Mobile, 350 U.S. 332; Sierra, 350 U.S. 348). 

266 Indicated Shippers Comments at 7 (citing 

United Gas Pipe Line Co. v. Memphis Light, Gas, 

& Water Division, 358 U.S.103 (1958) (Memphis)). 

In Williston Basin Pipeline Co. v. FERC, the Court 

stated: 

The label ‘‘Memphis clause’’ derives from the 

Supreme Court’s decision in United Gas Pipe Line 

Co. v. Memphis Light, Gas & Water Division, 

Continued 

reasonable rate pursuant to NGA section 

5. 

4. Take No Action (Option 4) 

a. NOPR 

226. Upon filing FERC Form No. 501– 

G, a pipeline may choose to take no 

action other than submitting FERC Form 

No. 501–G (Option 4). 

b. Comments 

227. Some entities commented on this 

option,252 generally stating that the 

Commission should require pipelines 

choosing this option to include at least 

a statement of the basis for that 

decision.253 Indicated Shippers 

similarly comment that the Commission 

should combine Option 4 with Option 

3 and clarify that a pipeline electing the 

take no action option must submit a 

notice that it will not be adjusting rates 

with its FERC Form No. 501–G filing, 

including an explanation for why the 

pipeline is doing nothing.254 NGSA 

suggests that the Commission eliminate 

Option 4 altogether, stating that it 

provides pipelines with an incentive to 

delay the process of providing rate relief 

to customers and consumers.255

c. Discussion 

228. The Commission declines to 

provide the requested clarification or to 

require statements of explanation as 

suggested by the commenters. As stated 

in the NOPR, the ‘‘no action’’ option is 

consistent with the fact that the 

Commission lacks authority to order an 

interstate pipeline to file a rate change 

under NGA section 4.256 Although the 

Commission is permitting interstate 

pipelines to voluntarily file a limited 

NGA section 4 filing or commit to make 

a general NGA section 4 filing to modify 

their rates to reflect the reduction in the 

income tax rates or elimination of the 

MLP pipeline income tax allowance, the 

Commission is not requiring interstate 

pipelines to make such filings. As the 

Commission also stated, however, based 

on the information contained in the 

individual pipeline’s FERC Form No. 

501–G, and comments by interested 

parties on that information, the 

Commission will consider initiating an 

NGA section 5 investigation of a 

particular pipeline’s rates if it appears 

those rates may be unjust and 

unreasonable. 

D. Negotiated Rates 

229. In the NOPR, the Commission 

stated that it has granted most interstate 

natural gas pipelines authority to 

negotiate rates with individual 

customers that are not bound by the 

maximum and minimum rates in the 

pipeline’s tariff. The Commission noted 

that before it permits a pipeline to 

implement a negotiated rate a pipeline 

must have a cost-based recourse rate on 

file with the Commission, so that a 

customer always has the option of 

entering into a contract at the cost-based 

recourse rate rather than a negotiated 

rate if it chooses.257

230. The Commission stated that 

changes to a pipeline’s recourse rates 

occurring under NGA sections 4 and 5 

would not affect a customer’s negotiated 

rate because that rate is negotiated as an 

alternative to the customer taking 

service under the recourse rate.258 By 

allowing the pipeline to negotiate 

individualized rates, the Commission 

permitted pipelines, as a means of 

providing rate certainty, to negotiate a 

fixed rate or rate formula that would 

continue in effect regardless of changes 

in the pipeline’s maximum recourse 

rate.259 Therefore, the Commission 

found that, ‘‘unless a negotiated rate 

agreement expressly provides otherwise, 

the rates in such agreements will be 

unaffected by any reduction in the 

pipeline’s maximum rate . . . resulting 

from the policies adopted in the 

rulemaking proceeding, whether in a 

limited or general NGA section 4 rate 

proceeding or a subsequent NGA section 

5 investigation.’’ 260

1. Comments 

231. Boardwalk argues that the 

Commission has specifically recognized 

the role of negotiated rate agreements in 

providing rate certainty to pipelines and 

their shippers,261 and maintains that the 

Commission should not reduce any 

negotiated rates due to recent tax policy 

changes (unless the agreement 

specifically requires such a reduction). 

232. Boardwalk argues that this 

position is consistent with the MobileSierra doctrine,262 because the courts 

require that in order to modify such 

contracts, the Commission must satisfy 

the Mobile-Sierra standard, under which 

the Commission must ‘‘presume that the 

rate set out in a freely negotiated 

contract meets the just and reasonable 

requirement imposed by law.’’ 263

Boardwalk asserts that the Commission 

may only modify a contract under 

Mobile-Sierra if it demonstrates ‘‘that 

the contract seriously harms the public 

interest,’’ which generally requires ‘‘a 

finding that the existing rate might 

impair the financial ability of [the 

pipeline] to continue its service, or that 

the rate would cast upon other 

consumers an excessive burden, or be 

unduly discriminatory, or that there are 

other circumstances of unequivocal 

public necessity.’’ 264 Boardwalk 

maintains that a change in the corporate 

tax rate or Commission policy cannot 

satisfy this high threshold. 

233. Indicated Shippers argue that the 

Commission has the authority to revise 

negotiated rate contracts under the 

Mobile-Sierra doctrine to revise any 

contract if the public interest requires a 

modification 265 and therefore, the 

Commission should ensure that each 

negotiated rate contract is examined. 

They assert that given the change in 

circumstances related to reductions in 

income tax rates, as well as the need to 

remove any unjust and unreasonable 

windfall for the natural gas pipeline 

companies, the Commission could find 

that the public interest requires such a 

finding. 

234. However, Indicated Shippers 

maintain that because many pipelines 

have a Memphis clause 266 in their 


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holding that a contract provision allowing a party 

to seek a rate adjustment under a suitable provision 

of the Natural Gas Act ([section] 4 for the utility, 

[section] 5 for the customer) obviates the need to 

apply Mobile-Sierra’s ‘‘public interest’’ criterion. 

The Memphis Court could see ‘‘no tenable basis of 

distinction between the filing of [a new rate under 

section 4 of the NGA] in the absence of a contract 

and a similar filing under an agreement which 

explicitly permits it.’’ Thus, a Memphis clause 

simply entitles a party to file for changes under an 

applicable provision of the NGA. 

519 F.3d 497, 499 (2008) (internal citations 

omitted). 

267 Indicated Shippers maintain that the 

Commission has a long court and Commission 

precedent to follow to allow for negotiated rate 

contracts to benefit from rate reduction through the 

application of the Memphis clause, unless there is 

a specific provision that explicitly prohibits 

changes to the negotiated rate or the applicability 

of the Memphis clause. Indicated Shippers 

Comments at 8 (citing Union Pac. Fuels v. FERC, 

129 F.3d 157, 161 (D.C. Cir. 1997); Papago Tribal 

Util. Auth. v. FERC, 723 F.2d 950, 953 (D.C. Cir. 

1983); Cost Recovery Mechanisms for 

Modernization of Natural Gas Facilities, 151 FERC 

¶ 61,047, at P 84 (2015) (Modernization Policy 

Statement); Sea Robin Pipeline Co., LLC, Opinion 

No. 516–A, 143 FERC ¶ 61,129, at PP 85–213 

(2013)). 

268 Indicated Shippers assert that the Commission 

utilized such a methodology for Account No. 858 

costs, Natural Gas Pipeline Co. of America, 70 

FERC ¶ 61,317, at 61,967–61,968 (1995); and 

hurricane-related costs, Sea Robin Pipeline Co., 128 

FERC ¶ 61,286, at PP 38–42 (2009), order on reh’g, 

130 FERC ¶ 61,191, at PP 11–13 (2010), Sea Robin 

Pipeline Co., LLC, Opinion No. 516, 137 FERC 

¶ 61,201 (2011), order on reh’g, Opinion No. 516– 

A, 143 FERC ¶ 61,129 at PP 146–151; High Island 

Offshore System, LLC, 145 FERC ¶ 61,155, at PP 16– 

20 (2013). 

269Range Comments at 10 (citing NOPR, FERC 

Stats. & Regs. ¶ 32,725 at P 45). 

270 Id. (citing INGAA, 285 F.3d at 31 (quoting 

Farmers Union Cent. Exch. v. FERC, 734 F.2d 1486, 

1502 (D.C. Cir. 1984), cert. denied, 469 U.S. 1034 

(1984))). 

271 Id. 

272 Id. (citing Elizabeth Gas Co. v. FERC, 10 F.3d 

866, 870 (D.C. Cir. 1993)). 

273 IOGA Comments at 7 (citing Dominion 

Transmission, Inc., 135 FERC ¶ 61,239, at P 30 

(2011)). 

274 Id. (citing Mobile, 350 U.S. 332; Sierra, 350 

U.S. 348; Morgan Stanley Capital Group, Inc. v. 

Public Utility District No. 1 of Snohomish County, 

Wash., 554 U.S. 527, 530 (FERC ‘‘must presume that 

the rate set out in a freely negotiated wholesaleenergy contract meets the ‘just and reasonable’ 

requirement imposed by law. The presumption may 

be overcome only if FERC concludes that the 

contract seriously harms the public interest.’’); 

Iberdrola Renewables, Inc. v. FERC, 597 F.3d at 

1301 (‘‘[N]egotiated rate customers are not left 

without redress if they think the rate has become 

unjust and unreasonable over time. They can 

always challenge the established rate under 

[S]ection 5. . . .’’)). 

service agreements and individual 

negotiated rate agreements, the 

Commission would only need to make 

a ‘‘just and reasonable’’ determination to 

revise negotiated rates.267 Indicated 

Shippers maintain that the Commission 

should establish a process to review 

each negotiated rate contract and 

examine the language set forth in each 

negotiated rate agreement to determine 

whether that agreement contains an 

explicit prohibition on rate reductions. 

235. Indicated Shippers assert that 

one way for the Commission to allow 

negotiated rate contracts to share in the 

subject cost reductions would be to 

implement a negative surcharge, 

applicable to all volumes on a particular 

system. Indicated Shippers assert that 

the Commission has implemented 

positive surcharges in certain 

instances 268 and many pipelines 

already have mechanisms in place for 

the return of over-collected amounts via 

a negative surcharge. 

236. Range requests that the 

Commission find, under the MobileSierra doctrine, that existing 

jurisdictional contracts between 

interstate pipelines and shippers 

including negotiated rate contracts 

which do not reflect the subject 

reduction in the corporate tax rate, are 

unjust and unreasonable under the 

NGA. Range states that the dramatic 

reduction in pipeline tax rates provides 

one of the few instances where the 

public interest requires the Commission 

to modify the rates under all shipper/ 

pipeline transportation contracts. 

237. If the Commission declines to 

make such a Mobile-Sierra finding, 

Range argues that the Commission has 

not provided a valid basis for excluding 

negotiated rate contracts from the Tax 

Cuts and Jobs Act rate reduction. Range 

asserts that the Commission’s reliance 

on the Negotiated Rate Policy Statement 

to exclude negotiated rate contracts 

from sharing in the Income Tax 

Reduction is misplaced. Range states 

that although the Commission allowed 

pipelines to negotiate individualized 

rates as a means of allowing the pipeline 

to provide rate certainty by the 

negotiation of a fixed rate or rate 

formula that would continue in effect 

regardless of changes in the pipeline’s 

maximum recourse rate, such 

permission does not support the 

Commission’s finding that a negotiated 

rate agreement will be unaffected by any 

reduction in the pipeline’s maximum 

rate reductions resulting from the 

policies adopted in the instant 

rulemaking unless the negotiated rate 

contract provides otherwise.’’ 269

238. Range states that the courts allow 

the Commission to exercise ‘‘lighthanded’’ regulation, but asserts that 

such regulation still is tied to the NGA 

and the ‘‘just and reasonable’’ standard. 

Range asserts that in INGAA, the court 

held that the ‘‘overarching criterion’’ 

was that such regulation based on other 

than only cost should be justified by ‘‘a 

showing that . . . the goals and 

purposes of the statute will be 

accomplished,’’ and to satisfy that 

standard, the court ‘‘demanded that the 

resulting rates be expected to fall within 

a ‘zone of reasonableness, where [they] 

are neither less than compensatory nor 

excessive.’ ’’ 270 Range states that INGAA 

also held that ‘‘[w]hile the expected 

rates’ proximity to cost was a starting 

point for this inquiry into 

reasonableness . . . ‘non-cost factors 

may legitimate a departure from a rigid 

cost-based approach,’ ’’ and that ‘‘we 

said that FERC must retain some general 

oversight over the system, to see if 

competition in fact drives rates into the 

zone of reasonableness ‘or to check rates 

if it does not.’ ’’ 271 Moreover, Range 

states that the courts have held that 

competition normally provides a 

reasonable assurance that rates will 

approximate cost, at least over the long 

run.272 Range reasons that because the 

Commission assumes the negotiated 

rates approximate competitive rates, it 

follows that such rates must also 

approximate cost-based rates. Range 

alleges that the Commission has failed 

to apply these principles in excluding 

negotiated rate contracts from the tax 

reduction. Range asserts that this result 

is discriminatory, arbitrary and 

capricious, and not based on substantial 

evidence or reasoned decision-making. 

239. IOGA asserts that the 

Commission must review the language 

in individual contracts and aggressively 

use its NGA section 5 power to ensure 

that negotiated rates are just and 

reasonable. IOGA argues that the 

Commission’s suggestion in the NOPR 

that negotiated rate agreements would 

be unaffected in an NGA section 5 

investigation 273 is inconsistent with 

precedent and the presumption set out 

by the Mobile-Sierra doctrine that such 

contracts are just and reasonable.274

IOGA states that such a presumption 

can be overcome with a public interest 

showing in an NGA section 5 

proceeding. IOGA asserts that although 

the public interest standard may pose a 

high bar, the Commission should make 

clear in the Final Rule that it did not 

intend to suggest in the NOPR that NGA 

section 5 relief was unavailable to 

negotiated rate shippers. 

240. IOGA asserts that because not all 

shippers have equal bargaining leverage 

and often there is no firm capacity 

available at the recourse rate, the 

Commission should consider the 

context of the negotiated rate bargain in 

determining whether above maximum 

negotiated rates should be reduced like 

recourse rates. IOGA argues that 

although the parties may have bargained 

for a fixed negotiated rate the pipeline 

bargained for a rate that recovers its 


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275NGSA Comments at 8 (citing Sea Robin 

Pipeline Company, LLC, 130 FERC ¶ 61,261 (2010); 

High Island Offshore Sys., L.L.C., 138 FERC 

¶ 61,114 (2012) as relying on the contracts 

containing a Memphis clause to permit the 

pipelines to impose a surcharge on fixed, negotiated 

rate contracts). 

276Northern Natural Gas Co., 105 FERC ¶ 61,299 

at PP 15–16. See also Columbia Gulf Transmission 

Co., 109 FERC ¶ 61,152, at P 13, reh’g denied, 111 

FERC ¶ 61,338, emphasizing that: 

To the extent a pipeline and its shipper want to 

obtain rate certainty by agreeing to a rate that will 

remain in effect throughout the term of the service 

agreement, the Commission provides them an 

opportunity to do so by entering into a negotiated 

rate agreement. 

277Alternatives to Traditional Cost-of-Service 

Ratemaking for Natural Gas Pipelines and 

Regulation of Negotiated Transportation Services of 

Natural Gas Pipelines; Statement of Policy and 

Request for Comments, 74 FERC ¶ 61,076, at 

61,225–226 (1996), order on clarification, 74 FERC 

¶ 61,194 (1996), order on reh’g, 75 FERC ¶ 61,024, 

reh’g denied, 75 FERC ¶ 61,066, reh’g dismissed, 75 

FERC ¶ 61,291 (1996), petition denied sub nom. 

Burlington Res. Oil & Gas Co. v. FERC, 172 F.3d 918 

(D.C. Cir 1998). 

278 Iberdrola Renewables, Inc. v. FERC, 597 F.3d 

at 1304. 

279 Dominion Transmission, Inc. v. FERC, 533 

F.3d 845, 852–53 (D.C. Cir. 2008) (noting that FERC 

must ‘‘presume that the rate set out in a freely 

negotiated . . . contract meets the ‘just and 

reasonable’ requirement imposed by law.’’ See also 

Marathon Oil Co. v. Trailblazer Pipeline Co., 111 

FERC ¶ 61,236, at P 64 (2005) (‘‘Absent a 

compelling reason, the Commission does not 

believe it should second-guess the business and 

economic decisions between knowledgeable 

business entities when they enter into negotiated 

rate contracts.’’). 

federal income taxes and other costs 

that it recovers in the maximum 

recourse rate, not a rate that overrecovers its costs. IOGA maintains that 

it is neither just nor reasonable nor in 

the public interest for the Commission 

to permit such over-collection. IOGA 

concludes that the Commission should 

require any pipeline that declines to 

adjust negotiated rates to explain why 

an adjustment is not needed. 

241. NGSA also argues that negotiated 

rate contract holders should not be 

excluded from this tax reduction 

process because this would run contrary 

to Commission policy that allows the 

application of surcharges for 

extraordinary circumstances. NGSA 

argues that negotiated contracts often 

contain language with surcharge 

provisions to capture unforeseen items 

or special circumstances that are not 

part of the standard ratemaking 

process.275 NGSA maintains that if 

shippers with negotiated rate contracts 

are expected to share in costs incurred 

by pipelines for special situations, such 

as hurricanes or modernizations, then 

the Commission should also require that 

shippers share in cost reductions 

received by pipelines in special 

situations. 

242. NGSA requests that the 

Commission implement a negative 

surcharge mechanism, as warranted, for 

shippers with negotiated rate contracts. 

NGSA claims that this will ensure that 

all parties are afforded the opportunity 

to appropriately share in the benefits of 

the Tax Cuts and Jobs Act and Revised 

Policy Statement, and that pipeline rates 

are just and reasonable. 

243. AGA requests that the 

Commission confirm that where the 

pipeline required that the rate for 

capacity awarded under a negotiated 

rate agreement be no less than the 

pipeline’s otherwise applicable tariff 

rate, such that the negotiated rate is now 

equal to the otherwise applicable tariff 

rate, and the tariff rate is reduced 

pursuant to proceedings related to the 

Tax Cuts and Jobs Act, any such 

negotiated rate be similarly reduced. 

244. CAPP argues that the use of 

negotiated rates does not warrant the 

continuation of excessive recourse rates. 

CAPP argues that the rationale for this 

rate review extends to all pipelines, 

irrespective of the prevalence of 

negotiated rates on the pipeline. CAPP 

asserts that the fundamental purposes 

for which recourse rates are maintained 

is to provide an alternative to negotiated 

rates and a check on the exercise of 

market power. Therefore, CAPP argues 

that if a pipeline experiences a decline 

in income tax expense that warrants a 

reduction in its tariff rates, the use of 

negotiated rates and the impact of such 

contracting practices on its revenues has 

no impact on the justification for recomputing maximum tariff rates. 

2. Discussion 

245. The Commission declines to 

establish a process under which it 

would review every currently effective 

negotiated rate contract in order to 

determine whether that contract can and 

should be modified to reflect the 

pipeline’s reduced tax costs as a result 

of the Tax Cuts and Jobs Act or the 

elimination of MLP tax allowances. For 

the reasons discussed below, the 

Commission believes that, as a general 

matter, such contracts should be 

allowed to remain in effect without 

change. However, an individual shipper 

under such a contract is free to file a 

complaint pursuant to NGA section 5 

presenting evidence as to why its 

negotiated contract is unjust and 

unreasonable or contrary to the public 

interest and must be modified. 

Alternatively, if a shipper believes that 

the terms of its negotiated contract 

provide for a reduction in the negotiated 

rate to reflect the pipeline’s reduced tax 

costs and the pipeline has failed to 

comply with the contract, the shipper 

may file a complaint or seek to enforce 

the contract in a court. 

246. As the Commission has 

explained, the negotiated rate program 

allows ‘‘pipelines to negotiate 

individualized rates that [are] not 

constrained by the maximum and 

minimum rates in the pipeline’s 

tariff. . . . Additionally, it permit[s] 

pipelines as a means of providing rate 

certainty, to negotiate a fixed rate that 

would continue in effect regardless of 

changes in the pipeline’s maximum 

rate.’’ 276 In the Negotiated Rate Policy 

Statement establishing the negotiated 

rate program, the Commission explained 

that the program ‘‘would dispense with 

cost of service regulation for an 

individual shipper when mutually 

agreed upon by the pipeline and its 

shipper,’’ and ‘‘a recourse service found 

in the pipeline’s tariff would be 

available for those shippers preferring 

traditional cost of service rates.’’ 277

Indeed, as the court found in Iberdrola, 

the: 

premise of the negotiated rate regime is that 

FERC will not review freely negotiated rates, 

which are presumed to be reasonable when 

a recourse rate is also offered.278

247. Thus, when a shipper enters into 

a negotiated rate agreement, it should be 

aware that it is agreeing to a rate that is 

not based on traditional cost of service 

regulation and will not be reduced 

simply because the pipeline’s maximum 

recourse rate may, at some future date, 

be lower than the negotiated rate. 

Because the shipper’s negotiated rate is 

not based on cost of service regulation, 

there is no reason why a reduction in 

the pipeline costs, including a reduction 

in its tax costs, should necessarily lead 

to a reduction in the negotiated rate. 

Indeed, the Commission’s consistent 

practice in pipeline rate proceedings, 

whether conducted under NGA section 

4 or 5, has been to address only the 

pipeline’s recourse rates and not make 

any modifications in any shipper’s 

negotiated rate. In these circumstances, 

the Commission finds it reasonable to 

presume that a shipper’s freely 

negotiated rate contract continues to 

meet the just and reasonable 

requirement in the NGA, regardless of a 

reduction in the pipeline’s tax costs, 

absent a particular shipper filing a 

complaint that presents compelling 

reasons to initiate an NGA section 5 

investigation.279

248. Commenters take various 

positions on whether, if a complaint is 

filed, the Mobile-Sierra ‘‘public interest’’ 

presumption would apply to the 

negotiated rate agreement. Indicated 

Shippers assert that because many 

pipelines have Memphis clauses in their 


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280Boardwalk Comments at 10–13. 

281 Id. at 13. 

282See Composition of Proxy Groups for 

Determining Gas and Oil Pipeline Return on Equity, 

123 FERC ¶ 61,048, at PP 3, 47 (2008) (citing Fed. 

Power Comm’n v. Hope Natural Gas Co., 320 U.S. 

591 (1944)); see also Williston Basin Interstate 

Pipeline Co., 110 FERC ¶ 61,210 (2000) (balancing 

the Commission’s pro-competitive policies with the 

pipeline’s ability to focus discounts on less utilized 

parts of the system), and El Paso Natural Gas Co., 

163 FERC ¶ 61,078, at PP 128–137 (2018) (Order 

No. 538–B) (rejecting request to design pipeline’s 

rates so as to require it to share in the costs of its 

discounting). 

283Southern Star Comments at 11–12. 

284Alabama Elec. Coop v. FERC, 684 F2d 20, 27 

(D.C. Cir. 1982) (‘‘[R]ates should be based on the 

costs of providing service to the utility’s customers, 

plus a just and fair return on equity.’’). 

285AGA Comments at 2 (citing Modernization 

Policy Statement, 151 FERC ¶ 61,047 

(Modernization Policy Statement)); LDC Coalition 

Comments at 13. 

service agreements and individual 

negotiated rate agreements, the 

Commission would only need to make 

a ‘‘just and reasonable’’ determination to 

revise negotiated rates for such 

negotiated rates. IOGA and other 

shippers state that the Mobile-Sierra 

public interest standard would apply, 

but suggest that the public interest 

standard may be satisfied in the context 

of changes in law such as the Tax Cuts 

and Jobs Act. 

249. The Commission need not 

resolve these issues in this Final Rule. 

Rather, the Commission will address 

these issues, as relevant, in the context 

of an individual complaint that may be 

filed. 

E. Miscellaneous Clarifications 

250. Boardwalk comments that the 

Commission should recognize the 

effects of competition on the natural gas 

industry and the Commission’s rate 

making policies. Boardwalk asserts that 

pipelines have had no choice but to 

discount their transportation service 

rates to attract retail shippers in the face 

of competition. Thus, in Boardwalk’s 

view, such pipelines are already in a 

state of cost under-recovery. Boardwalk 

states that the NOPR and its 

contemplated approach of having 

transportation rates set arithmetically 

based on the content of FERC Form No. 

501–G have exacerbated this problem 

and affected the pipelines’ ability to 

attract capital.280 It also claims that 

although customers receive the benefit 

of competition in discounted rates, the 

pipelines, under the referenced NOPR 

approach, do not receive a 

commensurate benefit when the market 

propels rates upward. Boardwalk claims 

that this imbalance between pipelines 

and their investors and customers and 

consumers is ‘‘out of step’’ with the 

competitive market intended by the 

Commission’s policies, and that the 

NOPR worsens this imbalance by 

favoring one set of affected parties. It 

also claims that the processes 

contemplated by the NOPR are 

inconsistent with the Commission’s 

prohibition on single issue ratemaking. 

Accordingly, Boardwalk states that the 

Commission should expressly state that 

the ‘‘same processes offered here to 

adjust rates in light of the [Tax Cuts and 

Jobs Act] and revised Policy Statement 

will also be available to pipelines 

should there be a change to future tax 

policy, or any other policy affecting a 

key component of ratemaking.’’ 281

251. The Commission declines to 

speculate on future potential actions, or 

what measures it may take should there 

be a future increase in the federal 

corporate tax rate. However, the 

Commission recognizes the importance 

of market issues and the potential for 

under-recoveries.282 The Commission 

takes the financial impact of its policies 

very seriously. The Commission will 

continue to consider the issues raised by 

Boardwalk as such issues arise in 

specific proceedings and as part of the 

Commission’s ongoing reevaluation of 

its policies. 

252. Further, regarding this Final 

Rule, the Commission recognizes that it 

cannot simply require a pipeline to 

reduce its rates consistent with a known 

reduction in a single cost component of 

a cost-based rate, but rather must 

consider other factors, including 

whether the pipeline is over-recovering 

its cost of service on an overall basis. 

The Commission, in deciding whether 

to exercise its discretion to initiate an 

NGA section 5 action, will take into 

account whether a rate reduction may 

not be justified because a pipeline’s 

rates do not over-recover its cost of 

service on an overall basis. 

253. Southern Star comments that the 

Commission should allow pipelines to 

reinvest any monetary savings resulting 

from the Tax Cuts and Jobs Act into 

their respective systems and 

infrastructure instead of flowing 

through the benefits to customers and 

consumers.283 Southern Star claims that 

rate reductions provided to ultimate 

consumers as a result of the tax 

reduction will be nominal, and that it 

would be a better use of those savings 

to permit pipelines to invest those 

dollars in infrastructure improvements 

that would benefit customers and 

ratepayers, and would obviate the need 

for the FERC Form No. 501–G filings. 

Southern Star asserts that such 

reinvestment would be consistent with 

the underlying purpose of the Tax Cuts 

and Jobs Act, namely to make more 

products in the United States and to 

‘‘bring back our companies.’’ 

254. The Commission rejects 

Southern Star’s proposal. As noted, the 

purpose of the Final Rule is to provide 

a process for considering whether to 

initiate NGA section 5 investigations of 

the cost-based recourse rates of 

interstate natural gas pipelines that do 

not voluntarily reduce those rates to 

reflect the reduction in the federal 

corporate tax rate or elimination of MLP 

tax allowances, in accordance with our 

obligation under the NGA to ensure that 

natural gas pipeline rates are just and 

reasonable. Contrary to Southern Star’s 

suggestion that it would be more 

efficient to reinvest these dollars in 

pipeline infrastructure than to return 

them to customers and consumers, a just 

and reasonable cost-based rate must be 

designed to provide the pipeline an 

opportunity to recover its cost of 

service, including a reasonable return 

on equity.284 The Commission lacks the 

authority to approve recourse rates that 

would allow pipelines to over-recover 

their cost of service. Pipelines are, of 

course, free to invest in additional 

pipeline facilities. If they do so, they 

may propose to adjust their rates to 

recover the costs of the new investment 

as part of their NGA section 7 initial rate 

proposal or in an NGA section 4 filing, 

and that rate adjustment could offset a 

rate reduction related to the pipeline’s 

reduced tax costs under the Tax Cuts 

and Jobs Act. 

255. AGA and LDC Coalition 

comment that the Commission should 

clarify that the FERC Form No. 501–G 

filing, or any other limited NGA section 

4 actions by a pipeline pursuant to the 

Final Rule, does not constitute a ‘‘recent 

rate review’’ sufficient for the purposes 

of the Commission’s Modernization 

Policy Statement on cost recovery 

mechanisms for modernization of 

natural gas facilities.285 The 

commenters state that the 

Modernization Policy Statement 

requires a pipeline seeking a 

modernization cost tracker to 

demonstrate that its current base rates 

are just and reasonable and reflect the 

pipeline’s current costs and revenues. 

LDC Coalition notes that the 

Modernization Policy Statement 

provides that the rate review condition 

may be satisfied in different ways—an 

NGA section 4 rate case or a 

collaborative effort between a pipeline 

and its customers. They also comment 

that the Commission left open the 

possibility that pipelines could justify 

their existing rates through ‘‘alternative 


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286AGA Comments at 7. 

287Modernization Policy Statement, 151 FERC ¶ 

61,047 at P 31. 

288LDC Coalition Comments at 15–16. 

289 Id. at 16. 

290 Id. 

291 Id. 

292 Id. at 18. 293NOPR, FERC Stats. & Regs. ¶ 32,725 at P 62. 

approaches.’’ 286 Thus, they seek 

clarification that a pipeline’s FERC 

Form No. 501–G filing would not be 

considered among the alternative 

approaches that the Commission would 

consider sufficient for a pipeline to 

justify its existing rates for purposes of 

the Modernization Policy Statement. 

Commenters argue that the information 

to be included in the FERC Form No. 

501–G filings is abbreviated cost and 

revenue information that would not 

allow for the ‘‘full exchange of 

information’’ regarding existing rates 

between the pipeline and its customers 

required for a modernization cost 

surcharge. 

256. The Commission provides the 

following clarification. Above, the 

Commission, in response to several 

pipeline comments, clarified that FERC 

Form No. 501–G is not an NGA section 

4 filing and that the indicated cost of 

service and estimated ROE are not NGA 

section 5 findings. The Commission has 

noted the statutory limits upon which 

the data collection is based, and 

acknowledges the limitations inherent 

in a form designed to collect data from 

a large number of pipelines with many 

unique cost of service, allocation and 

rate design factors underlying their 

currently effective rates. Thus, by the 

same token, these same limitations will 

hinder a pipeline from using its FERC 

Form No. 501–G filing, designed to look 

at a pipeline’s overall non-gas cost of 

service, to demonstrate that its 

modernization surcharges are just and 

reasonable. We also clarify that a 

limited NGA section 4 filing made 

pursuant to the Final Rule does not 

constitute a ‘‘recent rate review’’ 

sufficient for the purposes of the 

Commission’s Modernization Policy 

Statement on cost recovery mechanisms 

for modernization of natural gas 

facilities. The Modernization Policy 

Statement established certain standards 

a pipeline would have to satisfy for the 

Commission to approve a proposed 

modernization cost tracker or surcharge 

including a requirement for ‘‘a review of 

the pipeline’s existing base rates by 

means of an NGA general section 4 rate 

proceeding, a cost and revenue study, or 

through a collaborative effort between 

the pipeline and its customers.’’ 287 As 

described in the NOPR and the Final 

Rule, the limited NGA section 4 filing 

option is intended to allow interstate 

pipelines to reduce their rates to reflect 

the reduced income tax rates and 

elimination of the MLP pipeline income 

tax allowance on a single-issue basis, 

without consideration of any other cost 

or revenue changes. Due to the limited 

nature of this single-issue rate filing, it 

does not meet the rate review 

requirement described in the 

Modernization Policy Statement. 

257. LDC Coalition also seeks 

clarification that processes proposed in 

the NOPR do not obviate a pipeline’s 

settlement obligation to file an NGA 

general section 4 rate case.288

Specifically, they argue that any Final 

Rule should make clear that a pipeline 

cannot use the FERC Form No. 501–G 

filing, coupled with a limited NGA 

section 4 rate reduction filing, to satisfy 

a come-back obligation under a 

Commission-approved settlement. LDC 

Coalition asserts that the limited cost 

and revenue information in FERC Form 

No. 501–G, and the limited NGA section 

4 process, are not valid substitutes for 

a general NGA section 4 rate case filing, 

which provides parties the opportunity 

to review all the components of the 

pipeline’s cost of service. LDC Coalition 

comments further that such ‘‘comeback’’ provisions are ‘‘often hard-fought 

settlement components critical to 

garnering support from customer 

parties.’’ 289 Thus, it requests that the 

Commission clarify that a pipeline that 

‘‘has committed to file a general NGA 

section 4 rate case as a negotiated 

component of a Commission-approved 

settlement must fulfill that settlement 

commitment.’’ 290

258. The Commission declines to 

make the broad clarification sought by 

LDC Coalition. As LDC Coalition points 

out, the terms and details regarding a 

pipeline’s obligation to make future 

filings are likely provisions negotiated 

between the parties to the settlement, 

and as such are governed by the 

settlement itself. Thus, we will not 

make a general clarification that may 

inhibit or impinge on negotiated 

provisions of Commission approved 

settlements. 

259. LDC Coalition also states that the 

Commission should incorporate the 

FERC Form No. 501–G Implementation 

Guide into the Final Rule and into 

proposed regulation § 260.402.291 It 

asserts that such inclusion is necessary 

to ensure that Commission staff and 

interested parties are able to access the 

information necessary to adequately 

assess the pipeline’s report. LDC 

Coalition asserts that incorporation of 

the Implementation Guide into the Final 

Rule and Regulation, rather than just a 

reference to it in the proposed 

regulations, ‘‘would make clear that the 

Commission intends for customers and 

interested stakeholders to have access to 

the [report], and would help ensure 

compliance with the Commission’s 

desired filing processes.’’ 292

260. The Commission will not 

incorporate the FERC Form No. 501–G 

Implementation Guide into the Final 

Rule or into the proposed regulation or 

regulatory text. As LDC Coalition points 

out, the Commission included a 

Microsoft Excel version of the FERC 

Form No. 501–G and a proposed 

Implementation Guide as attachments to 

the NOPR, and thus made those files 

available in elibrary. The Commission 

intends to do the same for the Final 

Rule, and finds that the processes set 

forth in the guide, and data to be 

provided in the reports, will be 

adequately accessible to any interested 

parties in that manner. 

F. Implementation Schedule for 

Informational Filings 

1. NOPR 

261. In the NOPR, the Commission 

proposed a staggered filing schedule. 

The Commission identified 133 

interstate natural gas pipelines with 

cost-based rates that would be required 

to file the FERC Form No. 501–G, and 

divided them into four groups. The 

Commission proposed that the due date 

for the first group be 28 days from the 

effective date of any Final Rule in this 

proceeding, and the due date for each 

subsequent group be 28 days from the 

previous group’s due date. The NOPR 

stated that pipelines may file their FERC 

Form No. 501–G earlier than the 

proposed dates and respondents may 

include with this filing, as appropriate, 

an Addendum explaining why no 

adjustment in their rates is needed, or 

their commitment to make a general 

NGA section 4 rate case filing in lieu of 

a limited NGA section 4 filing as 

permitted by § 154.404.293

2. Comments 

262. Some commenters advocate for a 

delayed schedule. EQT Midstream urges 

the Commission to delay the FERC Form 

No. 501–G filing deadline for the first 

group of pipelines. EQT Midstream 

argues that the NOPR and Revised 

Policy Statement have made it unclear 

how to apply several ratemaking 

principles. EQT Midstream also argues 

that the 28 day deadline is not 

conducive to promoting settlements, as 

some parties may be wary to settle 

‘‘knowing that a Commission order 

addressing ADIT and the Revised Policy 


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294EQT Midstream Comments at 5. 

295Oklahoma AG Comments at 5. 

296Process Gas Comments at 7; Range Comments 

at 14. 

297Order No. 735, FERC Stats. & Regs. ¶ 31,310 

at P 96. Pipelines using state-approved rates 

pursuant to § 284.123(b)(1) may certify that those 

rates continue to meet the requirements of 

§ 284.123(b)(1) on the same basis on which they 

were approved. 

298 18 CFR 284.123(g)(9)(iii). See also Lobo 

Pipeline Co. L.P., 145 FERC ¶ 61,168, at P 5 (2013) 

and Atmos Pipeline—Texas, 156 FERC ¶ 61,094, at 

P 8 (2016). 

299Texas Railroad Commission Comments at 2 

(citing NOPR, FERC Stats. & Regs. ¶ 32,725 at PP 

58, 61). 

Statement may subsequently be issued 

and may upset any agreed-to terms.’’ 294

263. Other commenters advocate for 

an accelerated schedule. The Oklahoma 

AG requests that the Commission 

reduce the time period between FERC 

Form No. 501–G filings, then moving 

forward the final due date for filing rate 

cases.295 Process Gas requests that the 

Commission require all pipelines to file 

FERC Form No. 501–G within 28 days 

of the effective date of the Final Rule, 

rather than using a staggered schedule. 

Similarly, Range requests that the 

Commission require all pipelines to file 

FERC Form No. 501–G within 30 days 

of the effective date of the Final Rule, 

rather than using a staggered schedule. 

264. Process Gas states that it is not 

aware of any reason why any pipeline 

would need more than the 28 days 

allowed for the first group of pipelines 

to complete the form, especially since 

the 2017 FERC Form No. 2 data was due 

to be filed April 18, 2018. Range notes 

that pipelines have been planning for 

their filings ever since the issuance of 

the NOPR. Process Gas and Range 

concede that Commission staff may 

need time to process all of the filings, 

but argue that the solution is to stagger 

the issuance of the final orders, not the 

receipt of the filings. They argue all 

parties would benefit from having the 

FERC Form No. 501–G posted promptly. 

For those pipelines planning to 

voluntarily reduce their rates, Process 

Gas and Range argue, an earlier filing 

date would provide their customers 

with the benefit of lower rates as soon 

as possible. For those pipelines 

planning not to voluntarily reduce their 

rates, Process Gas argues, an earlier 

filing date would provide earlier insight 

into the pipeline’s rationale, allowing 

customers and Commission Staff more 

time to evaluate the filing and prepare 

an appropriate response.296

3. Discussion 

265. The Commission adopts the 

implementation schedule proposed in 

the NOPR, with one modification. The 

Commission has determined to combine 

the third and fourth groups of pipelines 

into a single group and require all those 

pipelines to file their FERC Form No. 

501–Gs within 28 days after the 

deadline for the second group of 

pipelines. This will allow the filing of 

all the FERC Form No. 501–Gs to be 

completed by early December of this 

year, rather than having the filing 

process extend into next year. We see no 

compelling reason to make any other 

changes in the implementation 

schedule. The Final Rule does not take 

effect instantly, but rather after a delay 

of 45 days after publication in the 

Federal Register, and the first set of 

pipeline filings is not due until 28 days 

after that. As a practical matter, then, 

pipelines in the initial filing group have 

over two months from the Commission’s 

approval of the Final Rule to prepare. 

266. We also decline to accelerate the 

filing schedule for the three pipeline 

groups. Commenters raise valid points 

in favor of requiring all pipelines to file 

simultaneously and instead staggering 

the target dates for final orders. We find, 

however, that the modified staggered 

schedule described above will allow the 

Commission to process the filings in a 

more efficient and orderly manner. We 

note that pipelines may file their FERC 

Form No. 501–G earlier than the 

proposed dates, and we especially 

encourage them to do so in instances 

where an early filing would ease the 

process of reaching a rate settlement 

with their customers. 

G. NGPA Section 311 and Hinshaw 

Pipelines 

1. NOPR 

267. In the NOPR, the Commission 

found that its existing regulations and 

policy concerning the rates charged by 

NGPA section 311 and Hinshaw 

pipelines are generally sufficient to 

provide shippers reasonable rate 

reductions with respect to the Tax Cuts 

and Jobs Act and the Revised Policy 

Statement. Accordingly, the 

Commission did not propose requiring 

NGPA section 311 and Hinshaw 

pipelines to file the FERC Form No. 

501–G or make any other immediate 

filing. Instead, the Commission 

proposed a separate method for 

updating NGPA section 311 and 

Hinshaw pipelines’ rates, in keeping 

with their history of light-handed 

regulation. 

268. Under pre-existing policy, the 

Commission reviews the rates of each 

NGPA section 311 and Hinshaw 

pipeline every five years.297 The 

Commission proposed using this fiveyear rate review process as the primary 

mechanism to consider changes to 

reflect the Tax Cuts and Jobs Act. 

269. The Commission proposed to act 

ahead of this five-year schedule only 

when a state regulatory agency requires 

any of these pipelines to reduce their 

intrastate rates to reflect the decreased 

income tax. Under pre-existing policy, 

any pipeline that elected to use statederived rates pursuant to § 284.123(b)(1) 

is already required to file with the 

Commission a new rate election 30 days 

after a state regulatory agency adjusts its 

intrastate rates.298 In the NOPR, the 

Commission proposed, for the purposes 

of the Tax Cuts and Jobs Act only, to 

expand this requirement to include 

intrastate pipelines that use 

Commission-established cost-based 

rates pursuant to § 284.123(b)(2), as well 

as pipelines that use state-derived rates 

pursuant to § 284.123(b)(1). 

Accordingly, the Commission proposed 

a new § 284.123(i) requiring that, if an 

intrastate pipeline’s rates on file with a 

state regulatory agency are reduced to 

reflect the reduced income tax rates 

adopted in the Tax Cuts and Jobs Act, 

the intrastate pipeline must file a new 

rate election within 30 days after the 

reduced intrastate rate becomes 

effective. The Commission reasoned that 

this requirement would give the same 

rate reduction benefit to any interstate 

shippers on those pipelines as the 

intrastate shippers receive, thereby 

ensuring that the two groups of shippers 

are treated similarly. 

2. Comments 

270. The Texas Railroad Commission, 

NiSource LDCs, and AGA commented 

on the portion of the NOPR affecting 

NGPA section 311 and Hinshaw 

pipelines. The Texas Railroad 

Commission, which is the state 

regulatory agency in Texas having 

jurisdiction over intrastate pipeline 

rates, supports this portion of the NOPR. 

The Texas Railroad Commission states 

that its experience with NGPA section 

311 and Hinshaw rates ‘‘is substantially 

the same as the Commission’s 

experience described in the . . . 

[NOPR].’’ 299 The Texas Railroad 

Commission notes that almost all 

intrastate contracts under Texas 

Railroad Commission jurisdiction are 

based on market conditions, and result 

in rates substantially lower than the 

maximum lawful rate. The Texas 

Railroad Commission states that it has 

already begun adjusting intrastate rates 

on local distribution systems. For 

transportation pipelines, the Texas 

Railroad Commission states that it 

intends to follow a process similar to 


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Federal Register / Vol. 83, No. 146 / Monday, July 30, 2018 / Rules and Regulations 36711 

300NiSource LDCs Comments at 5 (quoting 

NOPR, FERC Stats. & Regs. ¶ 32,725 at P 57). 301Columbia Gas of Maryland, Inc., Docket No. 

PR18–40–000 (filed April 3, 2018). 302NiSource LDCs Comments at 5. 303AGA Comments at 4. 304 Id. at 11. 

305 Id. at 13. 

306 Id. at 14. 307 18 CFR 284.224(a)(3). 

that described in the NOPR, revising 

existing rates as they are reviewed in the 

ordinary course of business. 

271. NiSource LDCs state that two of 

its affiliates are Hinshaw pipelines 

providing interstate transportation 

service under limited jurisdiction 

certificates issued by the Commission 

under § 284.224 of its regulations. 

NiSource LDCs agrees with the 

assessment in the NOPR that decisions 

on whether to reduce those rates to 

reflect the effects of the Tax Cuts and 

Jobs Act are ‘‘in the hands of the state 

regulatory agency.’’ 300 NiSource LDCs 

states that, if a state commission 

requires a reduction in such intrastate 

rates to reflect the impact of the Tax 

Cuts and Jobs Act, § 284.123(b) requires 

the company to make a corresponding 

rate filing with FERC within 30 days 

after the reduced intrastate rate becomes 

effective, and notes that it has already 

made one such filing with the 

Commission.301 NiSource ‘‘urge[s] the 

Commission to adopt this procedure 

with respect to companies holding 

limited jurisdiction certificates that 

have elected to charge state-approved 

transportation rates.’’ 302

272. AGA, whose members own or 

operate numerous Hinshaw pipelines, 

requests clarification of several points in 

the NOPR. AGA states that it ‘‘supports 

the efforts in the NOPR to obtain the 

information necessary’’ to ensure that 

interstate pipeline rates are just and 

reasonable,303 but argues that ‘‘any final 

rule should be consistent with the 

Commission’s focus on reducing 

regulatory burdens on [Hinshaw 

pipelines] not subject to full 

Commission-jurisdiction.’’ 304 AGA 

argues that Hinshaw services are 

generally very small in relation to 

interstate services, and that the Final 

Rule should, correspondingly, impose 

lesser requirements on Hinshaw 

services than on interstate services. 

273. AGA requests clarification of 

what action by a state commission 

triggers the obligation for an intrastate 

pipeline to file a new rate election 

under proposed § 284.123(i). AGA asks 

whether a pipeline must file with the 

Commission if the adjusted stateapproved rate is not comparable, or if 

the applicable state-approved rate 

references the Commission-established 

rate. AGA also notes that proposed new 

§ 284.123(i) refers to ‘‘intrastate’’ 

pipelines, and asks whether ‘‘the 

proposed text of paragraph (i) could be 

read to exclude § 284.224 certificate 

holders—Hinshaw pipelines and other 

local distribution companies—although 

it appears in the NOPR that the 

Commission intends to apply its 

requirements to intrastate pipelines and 

Hinshaw pipelines.’’ 305 AGA also asks 

that the Commission limit new 

§ 284.123(i) to only apply to pipelines 

with § 284.123(b)(2) Commissionestablished cost-based rates, reasoning 

that pipelines with § 284.123(b)(1) rates 

already must file within 30 days after a 

change in state rates. 

274. AGA also raises several timing 

issues. AGA notes that proposed new 

§ 284.123(i) would require entities to 

file a new rate election with the 

Commission ‘‘not later than 30 days 

after the reduced intrastate rate becomes 

effective.’’ AGA notes that this may 

cause confusion for any intrastate 

pipelines whose reduced rates at the 

state level become effective before the 

Commission issues a Final Rule. AGA 

also argues that local distribution 

companies are likely to need more time 

to prepare and file the new rate election 

with the Commission, and therefore 

proposes that the deadline in new 

§ 284.123(i) instead read: ‘‘not less than 

ninety (90) days after the latter of: the 

effective date of the final rule; or the 

effective date of the reduced intrastate 

rate (if effective after the effective date 

of a final rule).’’ 306 AGA also requests 

that any LDC that is subject to multiple 

state jurisdictions be permitted to wait 

until all jurisdictions have reviewed its 

rates before filing with the Commission. 

Finally, AGA states that the NOPR does 

not provide clear guidance to intrastate 

pipelines who have had rates approved 

in 2017 or 2018, who have currently 

pending proceedings, or who are due to 

make five-year rate review filings in the 

near future before the Final Rule takes 

effect. 

275. Similarly, AGA notes that the 

NOPR does not address whether filings 

to address the Tax Cuts and Jobs Act 

will re-set the five-year review period. 

AGA requests that the Commission 

confirm in any Final Rule that the filing 

of a rate election filing under 

§ 284.123(i) would re-set the currently 

applicable five-year review. 

276. Finally, AGA notes that the 

NOPR is unclear in terms of whether the 

Commission expects Hinshaw pipelines 

to file a fully updated cost and revenue 

study. AGA argues that unless it is made 

in the context of a regular five-year 

review, Hinshaw pipelines should have 

the option to simply re-file their rates on 

the limited issue of the Tax Cuts and 

Jobs Act impact. AGA also proposes that 

the Commission waive the filing fee for 

such filings. 

3. Discussion 

277. Noting the support for the NOPR 

as it applies to NGPA section 311 and 

Hinshaw pipelines, we generally adopt 

the NOPR’s proposal concerning those 

pipelines in this Final Rule, but also 

provide additional guidance on the 

points raised by AGA. 

278. First, new § 284.123(i) applies to 

§ 284.224 certificate holders. As 

§ 284.224(a)(3) states, Hinshaw 

pipelines and other local distribution 

companies, by accepting a certificate, 

are regulated ‘‘to the same extent that 

and in the same manner that intrastate 

pipelines are. . . .’’ 307 Therefore, the 

reference in new § 284.123(i) to 

‘‘intrastate pipelines’’ in no way 

excludes Hinshaw pipelines and other 

local distribution companies that hold 

§ 284.224 certificates. Moreover, the use 

of ‘‘intrastate pipelines’’ in § 284.123(i) 

is consistent with the remainder of 

§ 284.123, which refers to ‘‘intrastate 

pipelines’’ throughout. 

279. Second, we decline to revise new 

§ 284.123(i) to exclude § 284.123(b)(1) 

state-derived rates. Although it is 

current Commission policy to include in 

orders approving an intrastate pipeline’s 

state-derived rates a requirement that 

the pipeline must file a new rate 

election whenever the state-approved 

rate used in the rate election is changed, 

the Commission may not have included 

such a requirement in every such 

currently approved state-derived rate. 

Accordingly, we find that § 284.123(i) 

should apply to both § 284.123(b)(1) 

state-derived rates and § 284.123(b)(2) 

Commission-established cost-based 

rates so as to ensure that, if the 

intrastate pipeline’s rates on file with 

the state regulatory agency are reduced 

to reflect the reduced income tax rates 

adopted in the Tax Cuts and Jobs Act, 

the intrastate pipeline will file a new 

rate election for its interstate rates. 

However, we are revising proposed 

§ 284.123(i) in several respects in order 

to clarify how § 284.123(i) applies to 

these two different types of intrastate 

rates for interstate service. 

280. AGA requests that we clarify 

what type of rate change by a state 

regulatory agency triggers the 

§ 284.123(i) filing requirement. Under 

current Commission policy, an 

intrastate pipeline using state-derived 

rates under § 284.123(b)(1) must file a 

new rate election whenever the stateapproved rate used for its election is 


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36712 Federal Register / Vol. 83, No. 146 / Monday, July 30, 2018 / Rules and Regulations 

308AGA Comments at 13. 309 5 CFR 1320.11. 

changed. Consistent with that policy, 

we clarify that § 284.123(i) only requires 

such pipelines to make a new rate 

election when the state regulatory 

agency reduces the state-approved rate 

used for its rate election to reflect the 

reduced income taxes adopted in the 

Tax Cuts and Jobs Act. However, we 

find that a change by a state regulatory 

agency to the rate for any intrastate 

service due to the Tax Cuts and Jobs Act 

will trigger the § 284.123(i) filing 

requirement for intrastate pipelines 

whose existing interstate rates are 

Commission-established cost-based 

rates pursuant to § 284.123(b)(2). 

Interstate rates approved under 

§ 284.123(b)(2) are not based on any 

particular state-approved rate. In these 

circumstances, we find it reasonable for 

intrastate pipelines with § 284.123(b)(2) 

interstate rates to reduce those rates if 

the state regulatory agency reduces their 

rates for any intrastate service to reflect 

the reduced income taxes resulting from 

the Tax Cuts and Jobs Act. This ensures 

that interstate shippers receive a similar 

rate reduction as those intrastate 

customers whose rates are reduced and 

avoids the need to consider whether the 

intrastate rates reduced by the state 

regulatory agency are for an intrastate 

service comparable to the interstate 

service of the intrastate pipeline. 

281. AGA asks whether new 

§ 284.123(i) applies to any intrastate 

pipeline whose reduced intrastate rates 

‘‘become effective before the 

Commission issues a final rule.’’ 308 This 

is indeed the case. However, the 

Commission cannot impose a rule that 

has not yet gone into effect. 

Accordingly, in this Final Rule we 

modify proposed § 284.123(i) to clarify 

that the deadline for the required rate 

reduction filings will be 30 days after 

the later of (1) the effective date of the 

new § 284.123(i) or (2) the effective date 

of the reduction in the pipeline’s 

intrastate rates. 

282. AGA proposes that NGPA section 

311 and Hinshaw pipelines should have 

90 days from the effective date of the 

reduced intrastate rate to file with the 

Commission instead of 30 days. AGA 

also proposes that any local distribution 

companies subject to multiple state 

jurisdictions be permitted to wait until 

the last state government finishes its 

rate review before filing. We reject these 

proposals. Although individual 

pipelines are free to seek waiver if good 

cause exists, AGA’s proposals would 

only serve to delay the implementation 

of fair and equitable NGPA section 311 

and Hinshaw rates. A 90-day filing 

requirement in new § 284.123(i) would 

also create an unjustifiable difference in 

how the Commission treats pipelines 

with § 284.123(b)(2) rates versus 

pipelines with § 284.123(b)(1) rates, the 

latter of which already must file within 

30 days after a change in state rates. 

283. AGA states that the NOPR does 

not provide clear guidance to parties 

who have had rates approved in 2017 or 

2018, who have currently pending rate 

proceedings, or who are due to make 

five-year rate review filings in the near 

future before the Final Rule takes effect. 

Consistent with our policy that an 

intrastate pipeline whose existing 

interstate rates are based on 

§ 284.123(b)(1) must file a new rate 

election whenever the state-approved 

rate used for the election is changed, 

those interstate pipelines will have to 

file a new rate election if their state 

regulatory agency reduces the stateapproved rate used for their rate 

election, regardless of the pendency of, 

or Commission approval of, any prior 

rate filing by that intrastate pipeline. 

However, the Commission is revising 

proposed § 284.123(i) to provide that the 

requirement to file a new rate election 

in that section does not apply to 

intrastate pipelines using Commissionestablished cost-based rates under 

§ 284.123(b)(2), if the Commission has 

approved revised rates for that pipeline 

after December 22, 2017 or that pipeline 

already has a rate case pending before 

the Commission as of the date reduced 

intrastate rates become effective. Since 

the enactment of the Tax Cuts and Jobs 

Act on December 22, 2017, the 

Commission has not approved revised 

interstate rates for any intrastate 

pipeline under § 284.123(b)(2) without 

ensuring that the revised rates reflect 

the reduced income taxes adopted in the 

Tax Cuts and Jobs Act, and the 

Commission will continue to do so in 

all pending and future rate filings by 

such pipelines. Accordingly, there is no 

need for intrastate pipelines whose 

interstate rates are based on 

§ 284.123(b)(2) to file a new rate election 

in these circumstances. 

284. AGA also notes that the NOPR 

does not address whether filings to 

address the Tax Cuts and Jobs Act will 

re-set the five-year review period. The 

Commission intends for new 

§ 284.123(i) and the traditional five-year 

review policy to work in tandem. 

Accordingly, an accepted filing under 

§ 284.123(i) will reset the clock on the 

pipeline’s next five-year filing. Finally, 

AGA requests clarification regarding the 

filing fees, and content, of any filings 

addressing the Tax Cuts and Jobs Act. 

We clarify that the Commission has not 

changed its rules regarding filing fees, 

nor has the Commission changed its 

rules regarding the content of five-year 

review filings. Finally, we reject AGA’s 

proposal to permit anyone filing under 

§ 284.123(i) to submit a single-issue 

filing on the limited issue of the Tax 

Cuts and Jobs Act impact. Although we 

are permitting interstate natural gas 

pipelines regulated under the NGA to 

make such limited section 4 filings, as 

described above the interstate pipeline 

limited section 4 filings are based on 

financial information in the FERC Form 

No. 501–G, which is largely derived 

from FERC Form Nos. 2 and 2–A. 

Intrastate pipelines do not file such 

reports. Moreover, intrastate pipelines 

with cost-based interstate rates 

established by the Commission pursuant 

to § 284.123(b)(2) generally resolve their 

rate proceedings through black box 

settlements. As a result, it would be 

difficult, if not impossible, to determine 

how to adjust those rates solely to 

reflect reduced income taxes under the 

Tax Cuts and Jobs Act. State-derived 

rates adopted pursuant to 

§ 284.123(b)(1) would be changed 

consistent with whatever changes the 

state regulatory agency requires to 

reflect the income tax reductions in the 

Tax Cuts and Jobs Act. Accordingly, if 

the state regulatory agency approves a 

change in the relevant intrastate rate 

that is limited to reflecting the income 

tax reduction in the Tax Cuts and Jobs 

Act, the intrastate pipeline may make a 

similar rate reduction in its 

§ 284.123(b)(1) interstate rate. However, 

if the state regulatory agency revises the 

relevant intrastate rates based on a full 

review of all the intrastate pipelines 

costs and revenues, the interstate 

pipeline would have to make a similar 

change in its § 284.123(b)(1) interstate 

rate. 

H. Request for Commission Action 

285. We dismiss the Petitioners’ 

request for Commission action in Docket 

No. RP18–415–000 in light of the 

Commission’s actions in this 

rulemaking proceeding. 

V. Regulatory Requirements 

A. Information Collection Statement 

286. The Office of Management and 

Budget (OMB) regulations require that 

OMB approve certain reporting, record 

keeping, and public disclosure 

requirements (information collection) 

imposed by an agency.309 Upon 

approval of a collection of information, 

OMB will assign an OMB control 

number and an expiration date. 

Respondents subject to the filing 

requirements of a rule will not be 


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310Questar Southern Trails Pipeline Co., 163 

FERC ¶ 62,086 (2018). 

311Additional pipelines have chosen to file NGA 

section 4 rate filings before this Final Rule is 

effective; those pipelines will not be required to file 

the FERC Form No. 501–G. Because the number of 

pipelines choosing to make NGA section 4 filings 

may continue to change (correspondingly reducing 

the number of filers of the FERC Form No. 501–G), 

we are retaining a conservative estimate of 129 

pipelines who may be required to file the FERC 

Form No. 501–G. 

312The estimated average hourly cost of $83.97 

(rounded) assumes equal time is spent by an 

accountant, management, lawyer, and office and 

administrative support. The average hourly cost 

(salary plus benefits) is: $56.59 For accountants 

(occupation code 13–2011), $94.28 for management 

(occupation code 11–0000), $143.68 for lawyers 

(occupation code 23–0000), and $41.34 for office 

and administrative support (occupation code 43– 

0000). (The wage figures are taken from the Bureau 

of Labor Statistics [BLS], for May 2017, figures at 

https://www.bls.gov/oes/current/naics3_

221000.htm. BLS information on benefits for 

December 2017 was issued on March 20, 2018, at 

https://www.bls.gov/news.release/ecec.nr0.htm.) 

313 18 CFR 260.402 (as revised). 

314 18 CFR 154.404 (as revised). 

315 18 CFR 154.312. 

316The estimate for hours is based on the 

estimated average hours per response for the FERC– 

545 (OMB Control No. 1902–0154), with general 

NGA section 4, 18 CFR 154.312 filings weighted at 

a ratio of 20 to one. 

317 18 CFR 284.123(i) (as revised). 

318Estimate of number of respondents assumes 

that states will act within one year to reduce NGPA 

section 311 and Hinshaw pipeline rates to reflect 

the Tax Cuts and Jobs Act. 

319Number of unique respondents = (One-time 

Report) + (NGPA rate filing). 

penalized for failing to respond to the 

collection of information unless the 

collection of information displays a 

valid OMB control number. 

287. The Commission is submitting 

these reporting and recordkeeping 

requirements to OMB for its review and 

approval under section 3507(d) of the 

Paperwork Reduction Act (PRA). 

Comments are solicited on the 

Commission’s need for this information, 

whether the information will have 

practical utility, the accuracy of the 

provided burden estimate, ways to 

enhance the quality, utility, and clarity 

of the information to be collected, and 

any suggested methods for minimizing 

the respondent’s burden, including the 

use of automated information 

techniques. 

288. Public Reporting Burden: The 

Commission initially identified 133 

interstate natural gas pipelines with 

cost-based rates that will be required to 

file the adopted FERC Form No. 501–G. 

That figure was based upon a review of 

the pipeline tariffs on file with the 

Commission. However, the number has 

been reduced to 129 interstate natural 

gas pipelines, as the Commission 

removed Hampshire Gas Company as 

discussed above, Questar Southern 

Trails Pipeline Company, whom the 

Commission permitted to abandon its 

certificate to operate as a pipeline,310

MoGas, who filed a general NGA section 

4 rate case, and Granite State, who filed 

a prepackage uncontested settlement.311

Interstate natural gas pipelines have 

four options as to how to address the 

results of the formula contained in 

FERC Form No. 501–G. Each option has 

a different burden profile and a different 

cost per response. Companies will make 

their own business decisions as to 

which option they will select, thus the 

estimate for the number of respondents 

for each option as shown in the table 

below is just an estimate. 

289. The number of NGPA section 311 

and Hinshaw pipelines that will be 

required to file a rate case pursuant to 

proposed § 284.123(i) is a function of 

state actions outside of the control of the 

Commission. Thus, the estimate for the 

number of respondents for NGPA 

section 311 and Hinshaw pipelines 

filing a rate case in compliance with 

adopted § 284.123(i) as shown in the 

table below is an estimate. 

290. Based on these assumptions, we 

estimate the one-time burden and 

cost 312 for the information collection 

requirements as follows. 

FERC–501G 

Respondents 

Responses 

per 

respondent 

Total 

responses 

Average 

burden hour 

per response 

Average 

cost per 

response 

Total burden 

hours 

Total cost 

($) 

(1) (2) (1) * (2) = 

(3) 

(4) (5) (3) * (4) = (6) (3) * (5) = (7) 

Interstate Natural Gas Pipelines With Cost-Based Rates 

FERC Form No. 501–G, One-time Report 313 .................. 129 1 129 9 $756 1,161 $97,524 

Optional Response 

No Response .................................................................... 51 0 0 0 0 0 0 

Case for no change .......................................................... 62 1 62 5 420 310 26,040 

Limited Sec 4 filing 314 ...................................................... 15 1 15 6 504 90 7,560 

General Sec. 4 filing 315 .................................................... 1 1 1 316 512 42,968 512 42,968 

NGPA section 311 and Hinshaw Pipelines With Cost-Based Rates 

NGPA rate filing 317 ........................................................... 318 15 1 15 24 2,015 360 30,225 

TOTAL ........................................................................ 319 144 .................... 222 ...................... .................... 2,433 204,317 

291. The Report andany tariff filing 

option that an NGA natural gas 

company may choose or an NGPA 

pipeline company may be required to 

file must be filed using the 

Commission’s eTariff filing format. This 

format requires the use of software that 

all respondents currently have or 

purchase on a per-use basis. For 

companies that do not have their own 

software and must contract for the 

service, the Commission estimates a cost 

of $300 per filing. We estimate 

approximately 40 of the NGA and NGPA 

pipeline company respondents will 

contract for eTariff filing services at an 

estimated total cost of $12,000. 

Therefore the total cost of the Final Rule 

is $216,317. 

292. The Commission does not expect 

any mandatory or voluntary reporting 

requirements other than those listed 

above. 

Action: Proposed information 

collection, FERC–501G (Rate Changes 

Relating to Federal Corporate Income 

Tax Rate for Interstate Natural Gas 

Pipelines). 

OMB Control No.: 1902–0302. 

Respondents: Interstate natural gas 

pipelines with cost-based rates, and 


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36714 Federal Register / Vol. 83, No. 146 / Monday, July 30, 2018 / Rules and Regulations 

320Regulations Implementing the National 

Environmental Policy Act, Order No. 486, FERC 

Stats. & Regs. ¶ 30,783 (1987) (cross-referenced at 41 

FERC ¶ 61,284. 

321See 18 CFR 380.4(a)(2)(ii), 380.4(a)(5) and 

380.4(a)(27). 

322 5 U.S.C. 601–612. 

323See 5 U.S.C. 601(3) (citing section 3 of the 

Small Business Act, 15 U.S.C. 623). Section 3 of the 

SBA defines a ‘‘small business concern’’ as a 

business which is independently owned and 

operated and which is not dominant in its field of 

operation. 

324 13 CFR 121.201 (Subsector 486—Pipeline 

Transportation; North American Industry 

Classification System code 486210; Pipeline 

Transportation of Natural Gas) (2017). ‘‘Annual 

Receipts’’ are total income plus cost of goods sold. 

325The estimated $756 is for respondents who file 

the One-time Report and choose to take no optional 

response. Only one respondent who files the Onetime Report and then chooses to make a general 

NGA section 4 filing is estimated to have a one-time 

cost of $42,968. These figures do not include the 

estimated cost of $300 per filing for approximately 

40 filers for the use of software to make these filing 

in the eTariff format. 

certain NGPA section 311 and Hinshaw 

pipelines. 

Frequency of Information: One-time, 

for each indicated reporting 

requirement. 

Necessity of Information: The 

Commission requires information in 

order to determine the effect of the Tax 

Cuts and Jobs Act on the rates of natural 

gas pipelines to ensure those rates 

continue to be just and reasonable. 

Internal Review: The Commission has 

reviewed the adopted information 

collection requirements and has 

determined that they are necessary. 

These requirements conform to the 

Commission’s need for efficient 

information collection, communication, 

and management within the energy 

industry. The Commission has specific, 

objective support for the burden 

estimates associated with the 

information collection requirements. 

Interested persons may obtain 

information on the reporting 

requirements or submit comments by 

contacting the Federal Energy 

Regulatory Commission, 888 First Street 

NE, Washington, DC 20426 (Attention: 

Ellen Brown, Office of the Executive 

Director, (202) 502–8663, or email 

DataClearance@ferc.gov). Comments 

may also be sent to the Office of 

Management and Budget (Attention: 

Desk Officer for the Federal Energy 

Regulatory Commission), by email at 

oira_submission@omb.eop.gov. 

B. Environmental Analysis 

293. The Commission is required to 

prepare an Environmental Assessment 

or an Environmental Impact Statement 

for any action that may have a 

significant adverse effect on the human 

environment.320 The actions taken here 

fall within categorical exclusions in the 

Commission’s regulations for rules 

regarding information gathering, 

analysis, and dissemination, and for 

rules regarding sales, exchange, and 

transportation of natural gas that require 

no construction of facilities.321

Therefore, an environmental review is 

unnecessary and has not been prepared 

in this rulemaking. 

C. Regulatory Flexibility Act 

294. The Regulatory Flexibility Act of 

1980 (RFA) 322 generally requires a 

description and analysis of Final Rules 

that will have significant economic 

impact on a substantial number of small 

entities. 

295. As noted in the above 

Information Collection Statement, 

approximately 129 interstate natural gas 

pipelines, both large and small, are 

respondents subject to the requirements 

adopted by this rule. In addition, the 

Commission estimates that another 59 

NGPA natural gas pipelines may be 

required to file restated rates pursuant 

to proposed § 284.123(i). However, the 

actual number of NGPA section 311 and 

Hinshaw pipelines that will be required 

to file is a function of actions taken at 

the state level. The Commission 

estimates that only 15 of the 59 NGPA 

natural gas pipelines will file a rate case 

pursuant to proposed § 284.123(i). 

296. Most of the natural gas pipelines 

regulated by the Commission do not fall 

within the RFA’s definition of a small 

entity,323 which is currently defined for 

natural gas pipelines as a company that, 

in combination with its affiliates, has 

total annual receipts of $27.5 million or 

less.324 For the year 2016 (the most 

recent year for which information is 

available), only five of the 129 interstate 

natural gas pipeline respondents had 

annual revenues in combination with 

their affiliates of $27.5 million or less 

and therefore could be considered a 

small entity under the RFA. This 

represents 3.9 percent of the total 

universe of potential NGA respondents 

that may have a significant burden 

imposed on them. For NGPA section 

311 and Hinshaw pipelines, three of the 

59 potential respondents could be 

considered a small entity, or 5.1 

percent. However, it is not possible to 

predict whether any of these small 

companies may be required to make a 

rate filing. The estimated cost for 

respondents is expected to vary from 

$756 to $42,968.325 In view of these 

considerations, the Commission certifies 

that this final rule’s amendments to the 

regulations will not have a significant 

impact on a substantial number of small 

entities. 

D. Document Availability 

297. In addition to publishing the full 

text of this document in the Federal 

Register, the Commission provides all 

interested persons an opportunity to 

view and/or print the contents of this 

document via the internet through the 

Commission’s Home Page www.ferc.gov 

and in the Commission’s Public 

Reference Room during normal business 

hours (8:30 a.m. to 5:00 p.m. Eastern 

time) at 888 First Street NE, Room 2A, 

Washington, DC 20426. 

298. From the Commission’s Home 

Page on the internet, this information is 

available on eLibrary. The full text of 

this document is available on eLibrary 

in PDF and Microsoft Word format for 

viewing, printing, and/or downloading. 

To access this document in eLibrary, 

type the docket number excluding the 

last three digits in the docket number 

field. 

299. User assistance is available for 

eLibrary and the Commission’s website 

during normal business hours from 

FERC Online Support at (202) 502–6652 

(toll free at 1–866–208–3676) or email at 

ferconlinesupport@ferc.gov, or the 

Public Reference Room at (202) 502– 

8371, TTY (202) 502–8659. Email the 

Public Reference Room at 

public.referenceroom@ferc.gov. 

E. Effective Date and Congressional 

Notification 

300. These regulations are effective 

September 13, 2018. The Commission 

has determined, with the concurrence of 

the Administrator of the Office of 

Information and Regulatory Affairs of 

OMB, that this rule is not a ‘‘major rule’’ 

as defined in section 351 of the Small 

Business Regulatory Enforcement 

Fairness Act of 1996. 

List of Subjects 

Part 154 

Natural gas, Pipelines, Reporting and 

recordkeeping requirements. 

Part 260 

Natural gas, Reporting and 

recordkeeping requirements, 

Part 284 

Continental shelf, Natural gas, 

Reporting and recordkeeping 

requirements. 

By the Commission. Commissioners 

LaFleur and Glick are concurring with a 

separate statement attached. 


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Federal Register / Vol. 83, No. 146 / Monday, July 30, 2018 / Rules and Regulations 36715 

Issued: July 18, 2018. 

Nathaniel J. Davis, Sr., 

Deputy Secretary. 

In consideration of the foregoing, the 

Commission amends parts 154, 260, and 

284, Chapter I, Title 18, Code of Federal 

Regulations, as follows: 

PART 154—RATE SCHEDULES AND 

TARIFFS 

■ 1. The authority citation for part 154 

continues to read as follows: 

Authority: 15 U.S.C. 717–717w; 31 U.S.C. 

9701; 42 U.S.C. 7102–7352. 

■ 2. Add § 154.404 to subpart E to read 

as follows: 

§ 154.404 Tax Cuts and Jobs Act rate 

reduction. 

(a) Purpose. The limited rate filing 

permitted by this section is intended to 

permit: 

(1) A natural gas company subject to 

the Federal corporate income tax to 

reduce its maximum rates to reflect the 

decrease in the federal corporate income 

tax rate pursuant to the Tax Cuts and 

Jobs Act of 2017; and 

(2) A natural gas company organized 

as a pass-through entity either: 

(i) To eliminate any income tax 

allowance and accumulated deferred 

income taxes reflected in its current 

rates; or 

(ii) To reduce its maximum rates to 

reflect the decrease in the Federal 

income tax rates applicable to partners 

pursuant to the Tax Cuts and Jobs Act 

of 2017. 

(b) Applicability. (1) For purposes of 

paragraph (a)(1) of this section, a natural 

gas company organized as a passthrough entity all of whose income or 

losses are consolidated on the Federal 

income tax return of its corporate parent 

is considered to be subject to the 

Federal corporate income tax. 

(2) Except as provided in paragraph 

(b)(3) of this section, any natural gas 

company with cost-based, stated rates 

may submit the limited rate filing 

permitted by this section. 

(3) If a natural gas company has a rate 

case currently pending before the 

Commission in which the change in the 

Federal corporate income tax rate can be 

reflected, the public utility may not use 

this section to adjust its rates. 

(c) Determination of rate reduction. A 

natural gas company submitting a filing 

pursuant to this section shall reduce: 

(1) Its maximum reservation rates for 

firm service, and 

(2) Its usage charge that includes fixed 

costs, and 

(3) Its one-part rates that include fixed 

costs, by 

(4) The percentage calculated 

consistent with the instructions to FERC 

Form No. 501–G prescribed by § 260.402 

of this chapter. 

(d) Timing. Any natural gas company 

filing to reduce its rates pursuant to this 

section must do so no later than the date 

that it files its FERC Form No. 501–G 

pursuant to § 260.402 of this chapter. 

(e) Hearing issues. (1) The only issues 

that may be raised by Commission staff 

or any intervenor under the procedures 

established in this section are: 

(i) Whether or not the natural gas 

company may file under this section, 

(ii) Whether or not the percentage 

reduction permitted in paragraph (c)(4) 

has been properly applied, and 

(iii) Whether or not the correct 

information was used in that 

calculation. 

(2) Any other issue raised will be 

severed from the proceeding and 

dismissed without prejudice. 

PART 260—STATEMENTS AND 

REPORTS (SCHEDULES) 

■ 3. The authority citation for part 260 

continues to read as follows: 

Authority: 15 U.S.C. 717–717w, 3301– 

3432; 42 U.S.C. 7101–7352. 

■ 4. Add § 260.402 to read as follows: 

§ 60.402 FERC Form No. 501–G. One-time 

Report on Rate Effect of the Tax Cuts and 

Jobs Act. 

(a) Prescription. The form for the Onetime Report on Rate Effect of the Tax 

Cuts and Jobs Act of 2017, designated 

herein as FERC Form No. 501–G is 

prescribed. 

(b) Filing requirement—(1) Who must 

file. (i) Except as provided in paragraph 

(b)(1)(ii) of this section, every natural 

gas company that is required under this 

part to file a Form No. 2 or 2–A for 2017 

and has cost-based, stated rates for 

service under any rate schedule that was 

filed electronically pursuant to part 154 

of this chapter, must prepare and file 

with the Commission a FERC Form No. 

501–G pursuant to the definitions and 

instructions set forth in that form and 

the Implementation Guide. 

(ii) A natural gas company whose 

rates are being examined in a general 

rate case under section 4 of the Natural 

Gas Act or in an investigation under 

section 5 of the Natural Gas Act as of the 

deadline for it to file the FERC Form No. 

501–G need not file FERC Form No. 

501–G. In addition, a natural gas 

company that files an uncontested 

settlement of its rates pursuant to 

§ 385.207(a)(5) of this chapter after 

March 26, 2018, and before the deadline 

for it file the FERC Form No. 501–G 

need not file FERC Form No. 501–G. 

(2) FERC Form No. 501–G must be 

filed as prescribed in § 385.2011 of this 

chapter as indicated in the instructions 

set out in the form and Implementation 

Guide, and must be properly completed 

and verified. Each natural gas company 

must file FERC Form No. 501–G 

according to the schedule set forth in 

the Implementation Guide set out in 

that form. Each report must be prepared 

in conformance with the Commission’s 

form and guidance posted and available 

for downloading from the FERC website 

(http://www.ferc.gov). One copy of the 

report must be retained by the 

respondent in its files. 

PART 284—CERTAIN SALES AND 

TRANSPORTATION OF NATURAL GAS 

UNDER THE NATURAL GAS POLICY 

ACT OF 1978 AND RELATED 

AUTHORITIES 

■ 5. The authority citation for part 284 

continues to read as follows: 

Authority: 15 U.S.C. 717–717z, 3301– 

3432; 42 U.S.C. 7101–7352; 43 U.S.C. 1331– 

1356. 

■ 6. In § 284.123, add paragraph (i) to 

read as follows: 

§ 284.123 Rates and charges. 

* * * * * 

(i) If an intrastate pipeline’s rates on 

file with the appropriate state regulatory 

agency are reduced to reflect the 

reduced income tax rates adopted in the 

Tax Cuts and Jobs Act of 2017, the 

intrastate pipeline must file a new rate 

election pursuant to paragraph (b) of 

this section in the following 

circumstances: 

(1) If the intrastate pipeline’s existing 

rates for interstate service are based on 

paragraph (b)(1) of this section, the 

intrastate pipeline must file a new rate 

election, if the state-approved rate used 

for its current rate election is changed 

to reflect the reduced income tax rates 

adopted in the Tax Cuts and Jobs Act. 

(2) If the intrastate pipeline’s existing 

rates for interstate service are based on 

paragraph (b)(2) of this section, the 

intrastate pipeline must file a new rate 

election, if any of its rates on file with 

the appropriate state regulatory agency 

are reduced to reflect the reduced 

income tax rates adopted in the Tax 

Cuts and Jobs Act, unless the 

Commission has approved revised 

interstate rates for that pipeline after 

December 22, 2017, or it has filed 

revised interstate rates that are pending 

before the Commission on the effective 

date of the reduced intrastate rates. 

(3) Any rate election required by this 

paragraph must be filed on or before the 

later of October 15, 2018 or 30 days after 


daltland on DSKBBV9HB2PROD with RULES2
36716 Federal Register / Vol. 83, No. 146 / Monday, July 30, 2018 / Rules and Regulations 

1United Airlines, Inc. v. FERC, 827 F.3d 122 (D.C. 

Cir. 2016). 

the reduced intrastate rate becomes 

effective. 

Note: The following attachments and 

appendix will not be published in the Code 

of Federal Regulations: 

Attachments 

The Attachments (FERC Form No. 

501–G and the Implementation Guide) 

will not be published in the Federal 

Register or the Code of Federal 

Regulations. The Attachments will be 

available in the Commission’s eLibrary 

and website. 

The following appendix will not 

appear in the Code of Federal 

Regulations. 

Appendix A 

Commenter Short name 

American Gas Association .......................................................................................................................................... AGA. 

American Public Gas Association ............................................................................................................................... APGA. 

Berkshire Hathaway Energy Pipeline Group; Northern Natural Gas Company and Kern River Gas Transmission 

Company.

Berkshire Hathaway. 

Boardwalk Pipeline Partners, LP ................................................................................................................................ Boardwalk. 

Canadian Association of Petroleum Producers .......................................................................................................... CAPP. 

Dominion Energy Cove Point LNG, LP ...................................................................................................................... Cove Point. 

Direct Energy Business Marketing, LLC and Interstate Gas Supply, Inc .................................................................. Direct Energy. 

Dominion Energy Transmission, Inc.; Dominion Energy Carolina Gas Transmission, LLC; Dominion Energy 

Questar Pipeline, LLC; Dominion Energy Overthrust Pipeline, LLC; and Questar Southern Trails Pipeline Company.

Dominion Energy. 

Eastern Shore Natural Gas Company ........................................................................................................................ Eastern Shore. 

Enable Mississippi River Transmission, LLC and Enable Gas Transmission, LLC. .................................................. Enable Interstate Pipelines 

EQT Midstream Partners, LP ...................................................................................................................................... EQT Midstream. 

Hampshire Gas Company ........................................................................................................................................... Hampshire. 

Hess Corporation ........................................................................................................................................................ Hess. 

Industrial Energy Consumers of America ................................................................................................................... IECA. 

Aera Energy, LLC, Anadarko Energy Services Company; Apache Corporation; BP Energy Company; 

ConocoPhillips Company; Occidental Energy Marketing, Inc.; Petrohawk Energy Corporation; and XTO Energy, Inc.

Indicated Shippers. 

Interstate Natural Gas Association of America ........................................................................................................... INGAA. 

Independent Oil & Gas Association of West Virginia, Inc. ......................................................................................... IOGA. 

Natural Gas Pipeline Company of America LLC; Tennessee Gas Pipeline Company, L.L.C.; Southern Natural 

Gas Company, L.L.C.; Colorado Interstate Gas Company, L.L.C.; Wyoming Interstate Company, L.L.C.; El 

Paso Natural Gas Company, L.L.C.; Mojave Pipeline Company, L.L.C.; Bear Creek Storage Company, L.L.C.; 

Cheyenne Plains Gas Pipeline Company, L.L.C.; Elba Express Company, L.L.C.; Kinder Morgan Louisiana 

Pipeline LLC; Southern LNG Company, L.L.C.; and TransColorado Gas Transmission Company LLC.

Kinder Morgan. 

New York State Electric & Gas Corporation and Rochester Gas and Electric Corporation ...................................... NYSEG. 

Millennium Pipeline Company, L.L.C .......................................................................................................................... Millennium. 

National Fuel Gas Supply Corporation and Empire Pipeline, Inc .............................................................................. National Fuel. 

Natural Gas Supply Association ................................................................................................................................. NGSA. 

Bay State Gas Company d/b/a Columbia Gas of Massachusetts; Columbia Gas of Kentucky, Inc.; Columbia Gas 

of Maryland, Inc.; Columbia Gas of Ohio, Inc.; Columbia Gas of Pennsylvania, Inc.; Columbia Gas of Virginia, 

Inc.; and Northern Indiana Public Service Company LLC.

NiSource LDCs. 

Mike Hunter, Oklahoma Attorney General .................................................................................................................. Oklahoma AG. 

Process Gas Consumers Group and American Forest and Paper Association ........................................................ Process Gas. 

Railroad Commission of Texas ................................................................................................................................... Texas Railroad Commission. 

Range Resources-Appalachia, LLC ............................................................................................................................ Range. 

Southern Company Services, Inc.; Alabama Power Company; Georgia Power Company; Gulf Power Company; 

Mississippi Power Company and Southern Power Company.

Southern Companies. 

Southern Star Central Gas Pipeline, Inc .................................................................................................................... Southern Star. 

Spectra Energy Partners, LP (SEP), Algonquin Gas Transmission, LLC; Big Sandy Pipeline, LLC; East Tennessee Natural Gas, LLC; Market Hub Partners Holding, LLC; Ozark Gas Transmission, L.L.C.; Saltville Gas 

Storage Company L.L.C.; and Texas Eastern Transmission, LP. SEP also has ownership interests in Gulfstream Natural Gas System, L.L.C.; Maritimes & Northeast Pipeline, L.L.C.; Sabal Trail Transmission, LLC; 

and Southeast Supply Header, LLC.

Spectra. 

Trailblazer Pipeline Company, LLC; Tallgrass Interstate Gas Transmission, LLC; and Rockies Express Pipeline 

LLC.

Tallgrass Pipelines. 

TransCanada Corporation ........................................................................................................................................... TransCanada. 

The Williams Companies, Inc. .................................................................................................................................... Williams. 

Xcel Energy Services Inc.; Northern States Power Company, a Minnesota corporation; Northern States Power 

Company, a Wisconsin corporation; Public Service Company of Colorado; and Southwestern Public Service 

Company. Also Alliant Energy Corporate Services; Wisconsin Power and Light Company and Interstate Power 

and Light Company.

LDC Coalition. 

Concurring Statement 

LaFLEUR, Commissioner, and GLICK, 

Commissioner, concurring: 

In companion orders issued today, the 

Commission (1) affirms the Revised Policy 

Statement on Treatment of Income Taxes 

(Revised Policy Statement) issued in 

response to the decision of the United States 

Court of Appeals for the District of Columbia 

Circuit (D.C. Circuit) in United Airlines; 1 (2) 

provides guidance regarding the treatment of 

Accumulated Deferred Income Taxes (ADIT) 

where the income tax allowance is 

eliminated from cost-of-service rates under 

the Commission’s post-United Airlines 

policy; and (3) issues a Final Rule that 

establishes procedures for the Commission to 

determine which jurisdictional natural gas 

pipelines may be collecting unjust and 

unreasonable rates in light of the income tax 

reductions provided by the Tax Cuts and Jobs 

Act and the Commission’s revised policy and 

precedent concerning tax allowances to 


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Federal Register / Vol. 83, No. 146 / Monday, July 30, 2018 / Rules and Regulations 36717 

2 894 F.2d 1372 (DC Cir. 1990). 

3Commissioner LaFleur has been on record in 

support of Section 5 reform for several years. 

Northern Natural Gas Co., 133 FERC ¶ 61,111 

(2010) (LaFleur, Comm’r, dissenting). 

address the double recovery issue identified 

by United Airlines. These are significant 

orders, and we write separately to provide 

some additional thoughts regarding these 

decisions. 

First, with respect to the ADIT guidance 

issued today, we confess to some frustration 

that the rate benefits that customers and 

shippers would otherwise receive from the 

Revised Policy Statement may be 

significantly reduced by the treatment of 

ADIT announced in today’s orders. As a 

matter of equity, we believe that the 

arguments for applying previously-accrued 

ADIT balances to reduce future rate base 

where a tax allowance is eliminated are 

compelling. However, based on the 

arguments presented in this docket regarding 

the Commission’s authority to mandate those 

reductions on a generic basis, it appears that 

such a directive would run afoul of the rule 

against retroactive ratemaking, as interpreted 

by the D.C. Circuit in Public Utilities 

Commission of State of California v. FERC.2

Nonetheless, we note that today’s order is 

simply guidance, and to the extent that 

customers or shippers in individual 

proceedings argue that such a reduction is 

legal in specific cases, we will consider those 

arguments on the appropriate record. 

Second, we believe that today’s Final Rule 

sharply highlights the need for a legislative 

fix to the lack of refund authority in Section 

5 of the Natural Gas Act (NGA).3 Under 

current law, the Commission’s ability to 

protect natural gas customers against unjust 

and unreasonable rates is compromised by its 

inability to set a refund date. We believe that 

current law provides a perverse incentive for 

protracted litigation and creates an 

asymmetry of leverage between pipelines 

seeking a rate increase under Section 4 of the 

NGA and complainants or the Commission 

under Section 5. 

With respect to the Final Rule, we believe 

that our lack of refund authority affected the 

balance the Commission was able to strike in 

today’s order. It is a clear tenet of cost-ofservice ratemaking that tax savings should 

flow through to ratepayers, and the 

Commission is rightly pursuing that goal in 

the Final Rule. However, because our Section 

5 ‘‘stick’’ under the NGA cannot effectively 

deliver timely relief to customers, the Final 

Rule proffers a series of ‘‘carrots’’ in the hope 

that pipelines will exercise their Section 4 

filing rights to quickly flow those tax benefits 

back to their customers. While we think the 

balance struck in the Final Rule is reasonable 

in light of our limited refund authority, we 

believe that the Commission would be better 

equipped to protect customers if the law 

were amended. 

Accordingly, we respectfully concur. 

Cheryl A. LaFleur, 

Commissioner. 

Richard Glick, 

Commissioner. 

[FR Doc. 2018–15786 Filed 7–27–18; 8:45 am] 

BILLING CODE 6717–01–P 


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