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Rule

Interstate and Intrastate Natural Gas Pipelines; Rate Changes Relating to Federal Income Tax Rate; American Forest & Paper Association

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Start Preamble Start Printed Page 36672

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.

Start Further Info

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

End Further Info End Preamble Start Supplemental Information

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. Introduction1
II. Background5
A. Tax Cuts and Jobs Act5
B. United Airlines Issuances6
C. Overview of Natural Gas Rates10
1. The Natural Gas Act10
2. The Natural Gas Policy Act of 197816
D. Request for Commission Action19
E. Notice of Proposed Rulemaking21
F. Comments on Notice of Proposed Rulemaking23
III. Overview of Final Rule29
IV. Discussion37
A. Treatment of Pass-through Entities37
1. NOPR37
2. Comments39
a. Challenges to the Commission's response to United Airlines41
b. Arguments Regarding the Implementation44
3. Discussion49
a. Limited Section 4 Filings51
b. FERC Form No. 501-G and Addendum58
c. Other Issues62
B. One-time Report63
1. Legal Authority67
a. Comments67
b. Discussion69
2. Burden of Proof77
a. Comments77
b. Discussion78
3. Docketing and Comments80
a. Comments81
b. Discussion84
4. Rights of Intervenors93
a. Comments94
b. Discussion95
5. Use of 10.55 Percent Indicative Return on Equity100
a. Comments101
b. Discussion103
6. Use of Stated Capital Structure107
a. Comments109
b. Discussion111
7. Accumulated Deferred Income Taxes116
a. Comments120
b. Discussion128
8. Who Must File153
a. Comments154
b. Discussion158
9. Miscellaneous Changes to FERC Form No. 501-G166
a. Comments and Discussion166
C. Additional Filing Options for Natural Gas Companies190
1. Limited NGA Section 4 Filing (Option 1)191
a. NOPR191
b. Comments193
c. Discussion198
Start Printed Page 36673
2. General NGA Section 4 Filing or Prepackaged Uncontested Settlement (Option 2)206
a. NOPR206
b. Comments207
c. Discussion211
3. Statement That No Adjustment in Rates Needed (Option 3)216
a. NOPR216
b. Comments218
c. Discussion222
4. Take No Action (Option 4)226
a. NOPR226
b. Comments227
c. Discussion228
D. Negotiated Rates229
1. Comments231
2. Discussion245
E. Miscellaneous Clarifications250
F. Implementation Schedule for Informational Filings261
1. NOPR261
2. Comments262
3. Discussion265
G. NGPA section 311 and Hinshaw Pipelines267
1. NOPR267
2. Comments270
3. Discussion277
H. Request for Commission Action285
V. Regulatory Requirements286
A. Information Collection Statement286
B. Environmental Analysis293
C. Regulatory Flexibility Act294
D. Document Availability297
E. Effective Date and Congressional Notification300

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-C [3] 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. Start Printed Page 36674501-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 pass-through 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 industry-wide 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-C [11] 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 double-recovery 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]

Start Printed Page 36675

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-of-service information. In addition, in lieu of submitting a general NGA section 4 rate case, a pipeline may submit a pre-packaged 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 cost-based 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 market-based 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 Start Printed Page 36676using 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 state-approved 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 market-based 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 Commission-approved 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 One-time 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 pre-packaged 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.Start Printed Page 36677

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 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).Start Printed Page 36678

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 non-MLP 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 pass-through 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 Start Printed Page 36679onto 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 non-MLP 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 pass-through 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-of-service 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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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 pass-through 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 Start Printed Page 366815 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 pass-through 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 pass-through 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 double-recovery 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 Start Printed Page 36682of 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 pass-through 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 One-time Report is an Excel spreadsheet with formulas.

64. The Commission stated that the Commission and interested parties could use this information in the One-time 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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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. FERC[98] 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] Start Printed Page 3668414 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 One-time 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 One-time 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 Start Printed Page 36685protests 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 cost-based 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 Start Printed Page 36686pipelines' 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 One-time 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 One-time 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]

Start Printed Page 36687

a. Comments

101. The Pipeline Commenters[124] 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. Start Printed Page 36688501-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 Start Printed Page 36689type 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 Start Printed Page 36690information 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 Start Printed Page 36691no 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 ADIT-related 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 pass-through 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 Pass-Through 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 pass-through 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-of-service rates.[149] ADIT is a regulatory Start Printed Page 36692construct 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-of-service 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 pass-through 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-of-service 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 pre-United 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 Start Printed Page 36693for 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 long-standing 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 ADIT-related 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 Start Printed Page 36694must 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-of-service 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 Start Printed Page 36695believes 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 Start Printed Page 36696investigation 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) post-date 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 One-time 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 cost-based, 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 Start Printed Page 36697moratorium.” [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 One-time 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 Start Printed Page 36698No. 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-of-service 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 Start Printed Page 36699display 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 market-based 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 cost-of-service item as every other cost-of-service item. Additionally, FERC Form No. 501-G, page 3, line 5 requests the removal of any other fuel related Start Printed Page 36700revenues 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-of-service 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 pass-through 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 Start Printed Page 36701file 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 Start Printed Page 36702efficient 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 pre-packaged 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 Start Printed Page 36703general 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 pre-packaged 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 Start Printed Page 36704full 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 industry-wide 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 cost-based, 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 Start Printed Page 36705reasonable 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 Mobile-Sierra 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 Start Printed Page 36706service 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 Mobile-Sierra 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 “light-handed” 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 Start Printed Page 36707federal income taxes and other costs that it recovers in the maximum recourse rate, not a rate that over-recovers 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 re-computing 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 Start Printed Page 36708service 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 Start Printed Page 36709approaches.” [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 “come-back” 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 Start Printed Page 36710Statement 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 five-year 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 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.[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 Start Printed Page 36711that 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 state-approved 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) Commission-established 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 state-approved rate used for its election is Start Printed Page 36712changed. 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 state-approved 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 Commission-established 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 Start Printed Page 36713penalized 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

RespondentsResponses per respondentTotal responsesAverage burden hour per responseAverage cost per responseTotal burden hoursTotal 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 31312911299$7561,161$97,524
Optional Response
No Response51000000
Case for no change62162542031026,040
Limited Sec 4 filing 314151156504907,560
General Sec. 4 filing 315111316 51242,96851242,968
NGPA section 311 and Hinshaw Pipelines With Cost-Based Rates
NGPA rate filing 317318 15115242,01536030,225
TOTAL319 1442222,433204,317

291. The Report and any 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 Start Printed Page 36714certain 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.

Start List of Subjects

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
End List of Subjects Start Signature

By the Commission. Commissioners LaFleur and Glick are concurring with a separate statement attached.

Start Printed Page 36715

Issued: July 18, 2018.

Nathaniel J. Davis, Sr.,

Deputy Secretary.

End Signature

In consideration of the foregoing, the Commission amends parts 154, 260, and 284, Chapter I, Title 18, Code of Federal Regulations, as follows:

Start Part

PART 154—RATE SCHEDULES AND TARIFFS

End Part Start Amendment Part

1. The authority citation for part 154 continues to read as follows:

End Amendment Part Start Authority

Authority: 15 U.S.C. 717-717w; 31 U.S.C. 9701; 42 U.S.C. 7102-7352.

End Authority Start Amendment Part

2. Add § 154.404 to subpart E to read as follows:

End Amendment Part
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 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.

(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.

Start Part

PART 260—STATEMENTS AND REPORTS (SCHEDULES)

End Part Start Amendment Part

3. The authority citation for part 260 continues to read as follows:

End Amendment Part Start Authority

Authority: 15 U.S.C. 717-717w, 3301-3432; 42 U.S.C. 7101-7352.

End Authority Start Amendment Part

4. Add § 260.402 to read as follows:

End Amendment Part
FERC Form No. 501-G. One-time Report on Rate Effect of the Tax Cuts and Jobs Act.

(a) Prescription. The form for the One-time 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.

Start Part

PART 284—CERTAIN SALES AND TRANSPORTATION OF NATURAL GAS UNDER THE NATURAL GAS POLICY ACT OF 1978 AND RELATED AUTHORITIES

End Part Start Amendment Part

5. The authority citation for part 284 continues to read as follows:

End Amendment Part Start Authority

Authority: 15 U.S.C. 717-717z, 3301-3432; 42 U.S.C. 7101-7352; 43 U.S.C. 1331-1356.

End Authority Start Amendment Part

6. In § 284.123, add paragraph (i) to read as follows:

End Amendment Part
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 Start Printed Page 36716the 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

CommenterShort name
American Gas AssociationAGA.
American Public Gas AssociationAPGA.
Berkshire Hathaway Energy Pipeline Group; Northern Natural Gas Company and Kern River Gas Transmission CompanyBerkshire Hathaway.
Boardwalk Pipeline Partners, LPBoardwalk.
Canadian Association of Petroleum ProducersCAPP.
Dominion Energy Cove Point LNG, LPCove Point.
Direct Energy Business Marketing, LLC and Interstate Gas Supply, IncDirect 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 CompanyDominion Energy.
Eastern Shore Natural Gas CompanyEastern Shore.
Enable Mississippi River Transmission, LLC and Enable Gas Transmission, LLC.Enable Interstate Pipelines
EQT Midstream Partners, LPEQT Midstream.
Hampshire Gas CompanyHampshire.
Hess CorporationHess.
Industrial Energy Consumers of AmericaIECA.
Aera Energy, LLC, Anadarko Energy Services Company; Apache Corporation; BP Energy Company; ConocoPhillips Company; Occidental Energy Marketing, Inc.; Petrohawk Energy Corporation; and XTO Energy, IncIndicated Shippers.
Interstate Natural Gas Association of AmericaINGAA.
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 LLCKinder Morgan.
New York State Electric & Gas Corporation and Rochester Gas and Electric CorporationNYSEG.
Millennium Pipeline Company, L.L.CMillennium.
National Fuel Gas Supply Corporation and Empire Pipeline, IncNational Fuel.
Natural Gas Supply AssociationNGSA.
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 LLCNiSource LDCs.
Mike Hunter, Oklahoma Attorney GeneralOklahoma AG.
Process Gas Consumers Group and American Forest and Paper AssociationProcess Gas.
Railroad Commission of TexasTexas Railroad Commission.
Range Resources-Appalachia, LLCRange.
Southern Company Services, Inc.; Alabama Power Company; Georgia Power Company; Gulf Power Company; Mississippi Power Company and Southern Power CompanySouthern Companies.
Southern Star Central Gas Pipeline, IncSouthern 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, LLCSpectra.
Trailblazer Pipeline Company, LLC; Tallgrass Interstate Gas Transmission, LLC; and Rockies Express Pipeline LLCTallgrass Pipelines.
TransCanada CorporationTransCanada.
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 CompanyLDC 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 Start Printed Page 36717address 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-of-service 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.

End Supplemental Information

Footnotes

1.  An 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).

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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).

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3.  SFPP, L.P., Opinion No. 511-C, 162 FERC ¶ 61,228, at P 9 (2018).

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4.  United 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.”

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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).

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7.  Throughout 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.

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8.  See Tax Cuts and Jobs Act 13001, 131 Stat. at 2096.

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9.  See id. 11011, 131 Stat. at 2063.

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10.  Inquiry Regarding the Commission's Policy for Recovery of Income Tax Costs, Notice of Inquiry, FERC Stats & Regs. ¶ 35,581 (2016).

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

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12.  Id. P 22.

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13.  Id. P 21.

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14.  Revised Policy Statement, FERC Stats. & Regs. ¶ 35,060.

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15.  Policy Statement on Income Tax Allowances, 111 FERC ¶ 61,139 (2005).

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16.  Revised Policy Statement, FERC Stats. ¶ Regs. 35,060 at P 3.

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18.  Most 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.

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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.

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20.  See, e.g., Trunkline Gas Co., 142 FERC ¶ 61,133, at P 24 n.28 (2013).

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21.  ANR Pipeline Co., 110 FERC ¶ 61,069, at P 18 (2005).

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22.  Midwestern Gas Transmission Co., 162 FERC ¶ 61,219 (2018); Dominion Energy Overthrust Pipeline, LLC, 162 FERC ¶ 61,218 (2018); Natural 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).

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24.  See 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).

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25.  Northern Natural Gas Co., 105 FERC ¶ 61,299, at PP 15-16 (2003).

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26.  Alternatives 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).

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30.  Section 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.

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34.  Contract 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.).

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35.  Petitioners 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.

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36.  15 U.S.C. 717i(a), 717m(a).

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37.  NOPR, 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 “One-time Report” or “FERC Form No. 501-G” in this Final Rule.

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38.  NOPR, FERC Stats. & Regs. ¶ 32,725 at PP 41-51.

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39.  Id. PP 4, 40 & n.8.

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40.  The list of commenters and the abbreviation used for each in this order are shown on Appendix A.

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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).

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

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43.  Id. P 36.

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44.  NGSA Comments at 3, 5.

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45.  APGA Comments at 5-7.

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46.  CAPP Comments at 3-4, 7.

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47.  Direct Energy Comments at 7.

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48.  CAPP Comments at 7.

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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.

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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.

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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.

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52.  INGAA Comments at 16-18; Williams Comments at 4, 14-15; Millennium Comments at 1.

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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.

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54.  Dominion Energy Comments at 3; INGAA Comments at 2.

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55.  Tallgrass Pipelines Comments at 4-9; EQT Midstream Comments at 2, 6-8.

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56.  INGAA Comments at 3; Boardwalk Comments at 2; Tallgrass Pipelines Comments at 4-9; EQT Midstream Comments at 2, 6-8.

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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.

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58.  APGA Comments at 6.

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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.

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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.

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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.

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63.  INGAA Comments at 21; Millennium Comments at 6-7.

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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.

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65.  Kinder Morgan Comments at 15.

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66.  Millennium Comments at 5-6.

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67.  AGA Comments at 5-6.

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68.  Spectra Comments at 28-29.

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69.  A 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.

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70.  As 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).

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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.

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72.  BP 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.”).

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73.  Similarly, 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.

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74.  However, 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).

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75.  As 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.

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

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

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78.  The 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 pass-thru entities” pursuant to the Tax Cuts and Jobs Act. See Tax Cuts and Jobs Act 11011, 131 Stat. at 2063.

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79.  See, 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.

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

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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”).

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82.  See 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).

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83.  The 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 pre-packaged uncontested rate settlement before the deadline for their One-time Report.

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84.  FERC 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).

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85.  Enable Interstate Pipelines Comments at 13-17; Southern Star Comments at 3-5; TransCanada Comments at 4-7.

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86.  Consumers Energy Co. v. FERC, 226 F.3d 777 (6th Cir. 2000) (Consumers).

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87.  Enable Interstate Pipelines Comments at 14.

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88.  Enable Interstate Pipelines Comments at 15.

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89.  Southern Star Comments at 3-4.

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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 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).

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91.  See, 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.

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92.  Consumers, 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.”).

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93.  Id. at 781.

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94.  See, e.g., Hattiesburg Industrial Gas Sales, L.L.C., 134 FERC ¶ 61,236 at P 13 (imposing a five-year rate review requirement on Hattiesburg Industrial Gas Sales, L.L.C.).

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95.  Narragansett Electric Co., 155 FERC ¶ 61,159, at P 2 & n.15 (2016).

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97.  An 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.

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98.  866 F.2d 487 (D.C. Cir. 1989).

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99.  See Southern Star Comments at 7.

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100.  18 CFR 284.7(d) (2011).

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101.  INGAA, 285 F.3d at 38.

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102.  Id. (emphasis added).

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103.  See, 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.

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104.  EQT Midstream Comments at 20; Spectra Comments at 11-12; Tallgrass Pipelines Comments at 23-24; TransCanada Comments at 16.

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105.  Spectra Comments at 12.

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106.  See NOPR, FERC Stats. & Regs. ¶ 32,725 at PP 43-44.

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107.  Id. P 29.

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108.  Id. P 64.

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109.  The Commission established eTariff Type of Filing Code (ToFC) 1430 for FERC Form No. 501-G filings.

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110.  Such 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).

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111.  See cases cited supra note 22.

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112.  See 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.

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

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114.  LDC Coalition Comments at 12.

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120.  See 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.”).

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122.  See, 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).

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123.  El Paso Natural Gas Co., Opinion No. 528, 145 FERC ¶ 61,040, at P 642 (2013), reh'g denied, Opinion No. 528-A, 154 FERC ¶ 61,120 (2016) (El Paso).

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124.  INGAA, Southern Star, Boardwalk, Dominion Energy, Williams, Tallgrass Pipelines, TransCanada, Enable Interstate Pipelines, Kinder Morgan, and Spectra.

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125.  NOPR, 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)).

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126.  Id. P 35.

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127.  Boardwalk Comments at 27-29; Enable Interstate Pipelines Comments at 22; INGAA Comments at 36-38; Kinder Morgan Comments at 23-26.

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128.  Boardwalk Comments at 28; INGAA Comments at 36.

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129.  Boardwalk Comments at 29.

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130.  Enable Interstate Pipelines Comments at 24.

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131.  Kinder Morgan Comments at 24.

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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.

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133.  Bear 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).

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134.  High Island Offshore System, L.L.C., 110 FERC ¶ 61,043, at P 147 (2005).

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135.  The 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).

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

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138.  See 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.

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139.  See proposed FERC Form No. 501-G, page 1, line 31.

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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.

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141.  ADIT NOI, 162 FERC ¶ 61,223.

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142.  Boardwalk Comments at 14.

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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.

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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.

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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.

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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.

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147.  Inquiry Regarding the Commission's Policy for Recovery of Income Tax Costs, Order on Rehearing, 164 FERC ¶ 61,030 (2018).

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148.  This 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.

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149.  See 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 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.”).

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150.  Arco Pipe Line Co., Opinion No. 351, 52 FERC ¶ 61,055, at 61,238 (1990).

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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).

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152.  See 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”).

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153.  City of Piqua v. FERC, 610 F.2d 950, 954 (D.C. Cir. 1979).

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154.  Public 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-of-service 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.

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155.  Public 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.”).

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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.

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157.  The 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.

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158.  For 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).

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159.  Of 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.

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160.  See, 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).

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161.  See Tax Cuts and Jobs Act 13001(d), 131 Stat. at 2099-2100.

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162.  AI93-5-000 Guidance, Question 8: Changes In Tax Law Or Rates (emphasis added).

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163.  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 (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) (cross-referenced at 72 FERC ¶ 61,300).

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

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166.  Id. at General Instructions, No. VIII.

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167.  See 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.).

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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.

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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.

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170.  National 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).

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171.  Further, 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.

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172.  Id. at Article VII.

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173.  See 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.”).

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174.  National 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).

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175.  Order No. 144-A, FERC Stats. & Regs. ¶ 30,340 at 30,128.

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176.  El Paso Natural Gas Co., L.L.C., 152 FERC ¶ 61,039, at P 88 (2015) (El Paso).

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177.  See 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).

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

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179.  NOPR, FERC Stats. & Regs. ¶ 32,725 at proposed 18 CFR 260.402(b)(1)(i); see id. P 26.

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

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181.  Id. PP 4, 26, proposed 18 CFR 260.402(b)(1)(ii).

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182.  Hampshire Comments at 3.

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183.  AGA Comments at 8.

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184.  Indicated Shippers Comments at 14-15.

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185.  Boardwalk 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.

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186.  INGAA Comments at 28; Kinder Morgan Comments at 30-31.

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187.  Cove Point Comments at 2; Dominion Energy Comments at 15; Williams Comments at 5-6.

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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.

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

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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.

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191.  INGAA Comments at 29; Kinder Morgan Comments at 32.

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192.  NOPR, 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.”).

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193.  For 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.

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194.  Although 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.

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195.  Eastern Shore Comments at 4 (citing Eastern Shore Natural Gas Co., 163 FERC ¶ 61,054 (2018)).

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196.  Eastern Shore Natural Gas Co., 163 FERC ¶ 61,054 at P 1.

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197.  Eastern Shore Natural Gas Co., 162 FERC ¶ 61,183 (2017).

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198.  EQT Midstream Comments at 13-14; Tallgrass Pipelines Comments at 19-20.

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199.  INGAA Comments at 39; Boardwalk Comments at 30.

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200.  Indicated Shippers Comments at 15-17.

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201.  See supra P 144.

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202.  Berkshire Hathaway Comments at Ex. A.

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203.  TransCanada Comments at 16.

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205.  See, e.g., Equitrans, L.P., 109 FERC ¶ 61,214, at P 14 (2004).

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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).

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207.  The 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).

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208.  Berkshire Hathaway Comments at Ex. A.

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209.  Spectra Comments at 28.

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

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211.  18 CFR 154.312 and 154.313.

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212.  TransCanada Comments at 16-17.

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

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214.  Id. P 44.

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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.

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216.  INGAA Comments at 29.

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217.  Id.; Williams Comments at 8; EQT Midstream Comments at 12-13; Kinder Morgan Comments at 33.

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218.  INGAA Comments at 30; Kinder Morgan Comments at 33.

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219.  INGAA Comments at 30 (citing NOPR, FERC Stats. & Regs. ¶ 32,725 at P 42).

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220.  Id.

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221.  EQT Midstream Comments at 18-19; Tallgrass Pipelines Comments at 22.

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222.  APGA Comments at 7 (noting that proposed § 154.404(c) permits the pipeline to reduce only its reservation rates).

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223.  APGA Comments at 4-5.

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224.  FERC 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 cost-of-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.

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225.  See 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).

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

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227.  Id. P 47.

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228.  Id.

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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.

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230.  Tallgrass Pipelines Comments at 15.

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231.  EQT Midstream Comments at 10.

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232.  INGAA Comments at 23-25.

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233.  Dominion Energy Comments at 13.

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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.

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235.  EQT Midstream Comments at 11.

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236.  Spectra Comments at 9.

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237.  EQT Midstream Comments at 19; Dominion Energy Comments at 11-12; Tallgrass Pipelines Comments at 22-23.

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238.  EQT Midstream Comments at 19; Tallgrass Pipelines Comments at 22-23.

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239.  Dominion Energy Comments at 12.

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240.  EQT Midstream Comments at 19; Tallgrass Pipelines Comments at 23.

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241.  EQT Midstream Comments at 19 (citing NOPR, FERC Stats. & Regs. ¶ 32,725 at P 15).

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242.  Id.

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243.  18 CFR 385.602(h)(1)(i); see also Mobil Oil Corp. v. FPC, 417 U.S. 283, 314 (1974).

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244.  NOPR, FERC Stats. & Regs. ¶ 32,725 at PP¶ 49-50.

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245.  Indicated Shippers Comments at 14-15.

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246.  LDC Coalition Comments at 19-21.

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247.  Id. at 21.

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248.  Direct Energy Comments at 4-5, 8; Range Comments at 11-13.

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249.  Direct Energy Comments at 8.

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250.  See NOPR, FERC Stats. & Regs. ¶ 32,725 at P 28.

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251.  Id. P 32.

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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.

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253.  Southern Companies Comments at 5.

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254.  Indicated Shippers Comments at 13.

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255.  NGSA Comments at 6.

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256.  NOPR, 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)).

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257.  NOPR, 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).

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258.  Id. P 15.

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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).

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

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261.  Boardwalk 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)).

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262.  Boardwalk 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) (Mobile-Sierra))).

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263.  Id. (citing Dominion Transmission, 533 F.3d at 853 (internal punctuation and citations omitted)).

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264.  Id.

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265.  Indicated Shippers Comments at 6 (citing Mobile, 350 U.S. 332; Sierra, 350 U.S. 348).

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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, 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).

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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)).

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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).

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269.  Range Comments at 10 (citing NOPR, FERC Stats. & Regs. ¶ 32,725 at P 45).

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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))).

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271.  Id.

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272.  Id. (citing Elizabeth Gas Co. v. FERC, 10 F.3d 866, 870 (D.C. Cir. 1993)).

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273.  IOGA Comments at 7 (citing Dominion Transmission, Inc., 135 FERC ¶ 61,239, at P 30 (2011)).

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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 wholesale-energy 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. . . .”)).

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275.  NGSA 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).

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276.  Northern 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.

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277.  Alternatives 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).

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278.  Iberdrola Renewables, Inc. v. FERC, 597 F.3d at 1304.

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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.”).

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280.  Boardwalk Comments at 10-13.

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281.  Id. at 13.

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282.  See 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).

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283.  Southern Star Comments at 11-12.

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284.  Alabama 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.”).

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285.  AGA Comments at 2 (citing Modernization Policy Statement, 151 FERC ¶ 61,047 (Modernization Policy Statement)); LDC Coalition Comments at 13.

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286.  AGA Comments at 7.

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287.  Modernization Policy Statement, 151 FERC ¶ 61,047 at P 31.

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288.  LDC Coalition Comments at 15-16.

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289.  Id. at 16.

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290.  Id.

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291.  Id.

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292.  Id. at 18.

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

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294.  EQT Midstream Comments at 5.

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295.  Oklahoma AG Comments at 5.

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296.  Process Gas Comments at 7; Range Comments at 14.

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297.  Order 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.

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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).

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299.  Texas Railroad Commission Comments at 2 (citing NOPR, FERC Stats. & Regs. ¶ 32,725 at PP 58, 61).

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300.  NiSource LDCs Comments at 5 (quoting NOPR, FERC Stats. & Regs. ¶ 32,725 at P 57).

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301.  Columbia Gas of Maryland, Inc., Docket No. PR18-40-000 (filed April 3, 2018).

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302.  NiSource LDCs Comments at 5.

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303.  AGA Comments at 4.

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304.  Id. at 11.

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305.  Id. at 13.

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306.  Id. at 14.

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308.  AGA Comments at 13.

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310.  Questar Southern Trails Pipeline Co., 163 FERC ¶ 62,086 (2018).

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311.  Additional 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.

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312.  The 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.)

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313.  18 CFR 260.402 (as revised).

314.  18 CFR 154.404 (as revised).

315.  18 CFR 154.312.

316.  The 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).

318.  Estimate 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.

319.  Number of unique respondents = (One-time Report) + (NGPA rate filing).

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320.  Regulations Implementing the National Environmental Policy Act, Order No. 486, FERC Stats. & Regs. ¶ 30,783 (1987) (cross-referenced at 41 FERC ¶ 61,284.

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321.  See 18 CFR 380.4(a)(2)(ii), 380.4(a)(5) and 380.4(a)(27).

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323.  See 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.

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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.

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325.  The estimated $756 is for respondents who file the One-time Report and choose to take no optional response. Only one respondent who files the One-time 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.

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1.  United Airlines, Inc. v. FERC, 827 F.3d 122 (D.C. Cir. 2016).

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2.  894 F.2d 1372 (DC Cir. 1990).

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3.  Commissioner 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).

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

BILLING CODE 6717-01-P