[Federal Register Volume 85, Number 102 (Wednesday, May 27, 2020)]
[Notices]
[Pages 31760-31773]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2020-11406]



[[Page 31760]]

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

[Docket No. PL19-4-000]


Inquiry Regarding the Commission's Policy for Determining Return 
on Equity

AGENCY:  Federal Energy Regulatory Commission, DOE.

ACTION: Policy statement on determining return on equity for natural 
gas and oil pipelines.

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SUMMARY:  On March 21, 2019, the Federal Energy Regulatory Commission 
issued a notice of inquiry seeking information and stakeholder views 
regarding whether, and if so how, it should modify its policies 
concerning the determination of the return on equity (ROE) to be used 
in designing jurisdictional public utility rates and whether any 
changes to the Commission's policies concerning public utility ROEs 
should be applied to interstate natural gas and oil pipelines. 
Concurrently with this Policy Statement, the Commission is issuing 
Opinion No. 569-A adopting changes to its policies concerning public 
utility ROEs. The Commission finds that, with certain exceptions to 
account for the statutory, operational, organizational and competitive 
differences among the industries, the policy changes adopted in Opinion 
No. 569-A should be applied to natural gas and oil pipelines. 
Accordingly, the Commission revises its policy and will determine 
natural gas and oil pipeline ROEs by averaging the results of the 
Discounted Cash Flow model and the Capital Asset Pricing Model, but 
will not use the Risk Premium model. In addition, the Commission 
clarifies its policies governing the formation of proxy groups and the 
treatment of outliers in proceedings addressing natural gas and oil 
pipeline ROEs. Finally, the Commission encourages oil pipelines to file 
revised FERC Form No. 6, page 700s for 2019 reflecting the revised ROE 
policy.

DATES:  This Policy Statement takes effect May 27, 2020.
Evan Steiner (Legal Information), Office of the General Counsel, 888 
First Street NE, Washington, DC 20426, (202) 502-8792, 
[email protected]
Monil Patel (Technical Information), Office of Energy Market 
Regulation, 888 First Street NE, Washington, DC 20426, (202) 502-8296, 
[email protected]
Seong-Kook Berry (Technical Information), Office of Energy Market 
Regulation, 888 First Street NE, Washington, DC 20426, (202) 502-6544, 
[email protected]


SUPPLEMENTARY INFORMATION:
    1. On March 21, 2019, the Commission issued a Notice of Inquiry 
(NOI) seeking information and stakeholder views to help the Commission 
explore whether, and if so how, it should modify its policies 
concerning the determination of the return on equity (ROE) to be used 
in designing jurisdictional rates charged by public utilities.\1\ The 
Commission also sought comment on whether any changes to its policies 
concerning public utility ROEs should be applied to interstate natural 
gas and oil pipelines.\2\ On November 21, 2019, the Commission issued 
Opinion No. 569 \3\ establishing a revised methodology for determining 
just and reasonable base ROEs for public utilities under the Federal 
Power Act (FPA). Concurrently with the issuance of this Policy 
Statement, the Commission is issuing Opinion No. 569-A adopting changes 
to the base ROE methodology established in Opinion No. 569.\4\
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    \1\ Inquiry Regarding the Commission's Policy for Determining 
Return on Equity, 166 FERC ] 61,207, at P 1 (2019).
    \2\ Id.
    \3\ Ass'n of Bus. Advocating Tariff Equity v. Midcontinent 
Indep. Sys. Operator, Inc., Opinion No. 569, 169 FERC ] 61,129 
(2019).
    \4\ Ass'n of Bus. Advocating Tariff Equity v. Midcontinent 
Indep. Sys. Operator, Inc., Opinion No. 569-A, 171 FERC ] 61,154 
(2020).
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    2. As explained below, we revise our policy for analyzing 
interstate natural gas and oil pipeline ROEs to adopt the methodology 
established for public utilities in Opinion Nos. 569 and 569-A, with 
certain exceptions to account for the statutory, operational, 
organizational and competitive differences among the industries. 
Specifically, we will determine just and reasonable natural gas and oil 
pipeline ROEs by averaging the results of Discounted Cash Flow model 
(DCF) and Capital Asset Pricing Model (CAPM) analyses, according equal 
weight to both models. In contrast to our methodology for public 
utilities, we retain the existing two-thirds/one-third weighting for 
the short-term and long-term growth projections in the DCF and will not 
use the risk premium model discussed in Opinion No. 569 and modified in 
Opinion No. 569-A (Risk Premium). In addition, we clarify our policies 
governing the formation of proxy groups and the treatment of outliers 
in natural gas and oil pipeline proceedings. Finally, as discussed 
below, we encourage oil pipelines to file updated FERC Form No. 6, page 
700 data for 2019 to reflect the revised ROE policy established herein.

I. Background

A. Natural Gas and Oil Pipeline ROE Policy

    3. The Supreme Court has stated that ``the return to the equity 
owner should be commensurate with the return on investments in other 
enterprises having corresponding risks. That return, moreover, should 
be sufficient to assure confidence in the financial integrity of the 
enterprise, so as to maintain its credit and to attract capital.'' \5\
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    \5\ Fed. Power Comm'n v. Hope Nat. Gas Co., 320 U.S. 591, 603 
(1944) (citing Missouri ex rel. Sw. Bell Tel. Co. v. Pub. Serv. 
Comm'n of Mo., 262 U.S. 276, 291 (1923) (Brandeis, J., concurring)).
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    4. Since the 1980s, the Commission has determined natural gas and 
oil pipeline ROEs using the DCF model.\6\ The DCF model is based on the 
premise that ``a stock's price is equal to the present value of the 
infinite stream of expected dividends discounted at a market rate 
commensurate with the stock's risk.'' \7\ The Commission uses the DCF 
model to estimate the return necessary for the pipeline to attract 
capital based upon the range of returns that the market provides 
investors in a proxy group of publicly traded entities with similar 
risk profiles. The Commission estimates the required rate of return for 
each member of the proxy group using the following formula:
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    \6\ Composition of Proxy Groups for Determining Gas and Oil 
Pipeline Return on Equity, 123 FERC ] 61,048, at P 3 (2008) (2008 
Policy Statement).
    \7\ Canadian Ass'n of Petroleum Producers v. FERC, 254 F.3d 289, 
293 (D.C. Cir. 2001) (CAPP v. FERC).

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k = D/P (1+.5g) + g

where k is the discount rate (or investors' required return), D is the 
current dividend, P is the price of stock at the relevant time, and g 
is the expected growth rate in dividends based upon the weighted 
averaging of short-term and long-term growth estimates (referred to as 
the two-step procedure). The Commission multiplies the dividend yield 
(dividends divided by stock price or D/P) by the expression (1+.5g) to 
account for the fact that dividends are paid on a quarterly basis. For 
purposes of the (1+.5g) adjustment, the Commission uses only the short-
term growth projection.\8\
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    \8\ Seaway Crude Pipeline Co. LLC, Opinion No. 546, 154 FERC ] 
61,070, at PP 198-200 (2016).
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    5. In the two-step DCF model, the Commission computes the expected 
growth rate (g) by giving two-thirds weight to a short-term growth 
projection and one-third weight to a long-term

[[Page 31761]]

growth projection.\9\ For the short-term growth projection, the 
Commission uses security analysts' five-year forecasts for each company 
in the proxy group, as published by the Institutional Brokers Estimated 
System (IBES).\10\ The long-term growth projection is based on 
forecasts, drawn from three different sources,\11\ of long-term growth 
of the economy as a whole as reflected in the Gross Domestic Product 
(GDP).\12\ For proxy group members that are master limited partnerships 
(MLPs), the Commission adjusts the long-term growth projection to equal 
50% of GDP.\13\
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    \9\ 2008 Policy Statement, 123 FERC ] 61,048 at P 6.
    \10\ Id.
    \11\ The three sources used by the Commission are Global 
Insight: Long-Term Macro Forecast--Baseline (U.S. Economy 30-Year 
Focus); Energy Information Agency, Annual Energy Outlook; and the 
Social Security Administration.
    \12\ 2008 Policy Statement, 123 FERC ] 61,048 at P 6 (citing Nw. 
Pipeline Co., Opinion No. 396-B, 79 FERC ] 61,309, at 62,383 (1997); 
Williston Basin Interstate Pipeline Co., 79 FERC ] 61,311, at 62,389 
(1997), aff'd, Williston Basin Interstate Pipeline Co. v. FERC, 165 
F.3d 54, 57 (D.C. Cir. 1999)).
    \13\ Id. P 96.
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    6. Because most natural gas and oil pipelines are wholly owned 
subsidiaries and their common stocks are not publicly traded, the 
Commission must use a proxy group of publicly traded firms with 
corresponding risks to set a range of reasonable returns.\14\ The firms 
in the proxy group must be comparable to the pipeline whose ROE is 
being determined, or, in other words, the proxy group must be ``risk-
appropriate.'' \15\ The range of the proxy group's returns produces the 
zone of reasonableness in which the pipeline's ROE may be set based on 
specific risks. Absent unusual circumstances showing that the pipeline 
faces anomalously high or low risks, the Commission sets the pipeline's 
cost-of-service nominal ROE at the median of the zone of 
reasonableness.\16\
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    \14\ Petal Gas Storage, L.L.C. v. FERC, 496 F.3d 695, 697 (D.C. 
Cir. 2007) (explaining that the purpose of a DCF proxy group is to 
``provide market-determined stock and dividend figures from public 
companies comparable to a target company for which those figures are 
unavailable. Market-determined stock figures reflect a company's 
risk level and when combined with dividend values, permit 
calculation of the `risk-adjusted expected rate of return sufficient 
to attract investors.' '' (quoting CAPP v. FERC, 254 F.3d at 293)).
    \15\ Id. at 699; see also Portland Nat. Gas Transmission Sys., 
Opinion No. 524, 142 FERC ] 61,197, at P 302 (2013), reh'g denied, 
Opinion No. 524-A, 150 FERC ] 61,107 (2015).
    \16\ El Paso Nat. Gas Co., Opinion No. 528, 145 FERC ] 61,040, 
at P 592 (2013), order on reh'g, Opinion No. 528-A, 154 FERC ] 
61,120 (2016), order on compliance & reh'g, Opinion No. 528-B, 163 
FERC ] 61,079 (2018) (citing Transcontinental Gas Pipe Line Corp., 
Opinion No. 414-A, 84 FERC ] 61,084 (1998), reh'g denied, Opinion 
No. 414-B, 85 FERC ] 61,323 (1998), aff'd, CAPP v. FERC, 254 F.3d 
289).
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B. Other Financial Models

    7. In the NOI, the Commission sought comment on other financial 
models the Commission has considered when determining ROE for public 
utilities, including the CAPM, Risk Premium model, and an expected 
earnings analysis (Expected Earnings).\17\
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    \17\ NOI, 166 FERC ] 61,207 at PP 35, 38.
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1. CAPM
    8. Investors use CAPM analysis as a measure of the cost of equity 
relative to risk.\18\ The CAPM is based on the theory that the market-
required rate of return for a security is equal to the ``risk-free 
rate'' plus a risk premium associated with that security. The CAPM 
estimates cost of equity by adding the risk-free rate to the ``market-
risk premium'' multiplied by ``beta.'' The formula for the CAPM is as 
follows:

    \18\ Opinion No. 569, 169 FERC ] 61,129 at P 229.
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R = rf + [beta]a(rm-rf)
rf = risk free rate (such as yield on 30-year U.S. Treasury bonds)
rm = expected market return
[beta]a = beta, which measures the volatility of the security compared 
to the rest of the market.

    The risk-free rate is represented by a proxy, typically the yield 
on 30-year U.S. Treasury bonds. The market-risk premium is calculated 
by subtracting the risk-free rate from the ``expected return,'' which, 
in a forward-looking CAPM analysis, is based on a DCF analysis of a 
large segment of the market, such as the dividend paying companies in 
the S&P 500.\19\ Betas measure the volatility of a particular stock 
relative to the market and are published by several commercial 
sources.\20\ An entity may also seek to apply a size premium adjustment 
to the CAPM zone of reasonableness to account for the difference in 
size between itself and the dividend paying companies in the S&P 
500.\21\
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    \19\ Id.
    \20\ NOI, 166 FERC ] 61,207 at P 14.
    \21\ See Opinion No. 569, 169 FERC ] 61,129 at P 298; see also 
Coakley v. Bangor Hydro-Elec. Co., Opinion No. 531-B, 150 FERC ] 
61,165, at P 117 (2015) (citing Roger A. Morin, New Regulatory 
Finance, 187 (Public Utilities Reports, Inc. 2006) (Morin) (finding 
that use of a size premium adjustment is ``a generally accepted 
approach to CAPM analyses'')).
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2. Risk Premium
    9. Risk premium methodologies are ``based on the simple idea that 
since investors in stocks take greater risk than investors in bonds, 
the former expect to earn a return on a stock investment that reflects 
a `premium' over and above the return they expect to earn on a bond 
investment.'' \22\ This difference reflects the greater risk of a stock 
investment.\23\ The risk premium return is calculated as follows:
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    \22\ Opinion No. 569, 169 FERC ] 61,129 at P 304 (quoting 
Coakley v. Bangor Hydro-Elec. Co., Opinion No. 531, 147 FERC ] 
61,234, at P 147 (2014)).
    \23\ Ass'n of Bus. Advocating Tariff Equity v. Midcontinent 
Indep. Sys. Operator, Inc., 165 FERC ] 61,118, at P 36 (2018) (MISO 
Briefing Order).

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R = I + RP

where I represents current applicable bond yield and RP represents the 
risk premium, which consists of the difference between (a) applicable 
annual common equity premiums and (b) applicable bond yields.
    10. Although there are multiple approaches to determining an 
entity's equity risk premium (RP), the Risk Premium model addressed in 
Opinion Nos. 569 and 569-A ``examin[es] the risk premiums implied in 
the returns on equity allowed by regulatory commissions for utilities 
over some past period relative to the contemporaneous level of the 
long-term U.S. Treasury bond yield.'' \24\ This approach develops the 
equity risk premium using Commission-allowed ROEs for public utilities 
minus the long-term bond yield.
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    \24\ Opinion No. 569, 169 FERC ] 61,129 at P 305.
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3. Expected Earnings
    11. A comparable earnings analysis is a method of calculating the 
earnings an investor expects to receive on the book value of a 
particular stock.\25\ The analysis can be either backward-looking using 
the company's historical earnings on book value, as reflected on the 
company's accounting statements, or forward-looking using estimates of 
earnings on book value, as reflected in analysts' earnings forecasts 
for the company. The latter approach is often referred to as an 
``Expected Earnings analysis.'' The Expected Earnings analysis provides 
an accounting-based approach that uses investment analyst estimates of 
return (net earnings) on book value (the equity portion of a company's 
overall capital, excluding long-term debt).\26\ Algebraically, Expected 
Earnings can be expressed as follows:
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    \25\ Id. P 172.
    \26\ Opinion No. 569, 169 FERC ] 61,129 at P 172.

R = E/B
E = Earnings during Current Year
B = Book Value at the End of the Prior Year

[[Page 31762]]

C. Public Utility ROE Proceedings Following Emera Maine v. FERC

1. Briefing Orders and Trailblazer
    12. Following the decision of the United States Court of Appeals 
for the District of Columbia Circuit (D.C. Circuit) in Emera Maine v. 
FERC,\27\ the Commission issued two briefing orders \28\ in the fall of 
2018 proposing a new methodology for analyzing public utility ROEs 
under FPA section 206.\29\ The Commission preliminarily found that ``in 
light of current investor behavior and capital market conditions, 
relying on the DCF methodology alone will not produce a just and 
reasonable ROE.'' \30\ The Commission found that investors appear to 
base their decisions on numerous financial models \31\ and may give 
greater weight to models other than the DCF in estimating the expected 
returns from a utility investment.\32\ As such, the Commission proposed 
to determine ROE for public utilities by averaging the results of DCF, 
CAPM, Expected Earnings, and Risk Premium analyses, giving equal weight 
to each analysis. The Commission established paper hearings and 
directed the parties in those proceedings to file briefs in response.
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    \27\ 854 F.3d 9 (D.C. Cir. 2017).
    \28\ MISO Briefing Order, 165 FERC ] 61,118; Coakley v. Bangor 
Hydro-Elec. Co., 165 FERC ] 61,030 (2018) (Coakley Briefing Order, 
and together with MISO Briefing Order, Briefing Orders).
    \29\ 16 U.S.C. 824e (2018).
    \30\ Coakley Briefing Order, 165 FERC ] 61,030 at P 32; MISO 
Briefing Order, 165 FERC ] 61,118 at P 34.
    \31\ Coakley Briefing Order, 165 FERC ] 61,030 at P 40; MISO 
Briefing Order, 165 FERC ] 61,118 at P 42.
    \32\ Coakley Briefing Order, 165 FERC ] 61,030 at P 35; MISO 
Briefing Order, 165 FERC ] 61,118 at P 37.
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    13. On February 21, 2019, while the paper hearings were pending, 
the Commission found in Trailblazer Pipeline Company LLC that 
``investor reliance upon multiple methodologies presumably applies to 
investments in natural gas pipelines'' as well as public utilities.\33\ 
The Commission therefore permitted parties in that natural gas pipeline 
cost-of-service rate proceeding to address the four alternative 
financial models at hearing.\34\
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    \33\ 166 FERC ] 61,141, at P 48 (2019).
    \34\ Thereafter, participants in natural gas pipeline rate 
proceedings in Docket Nos. RP19-352-000, RP19-1353-000, RP19-1523-
000, and RP20-131-000 filed testimony applying the alternative 
models.
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2. Opinion No. 569
    14. On November 21, 2019, the Commission issued Opinion No. 569 
adopting the proposal from the Briefing Orders, with several 
revisions.\35\ The Commission explained that it would use the DCF model 
and CAPM in its ROE analyses under FPA section 206 \36\ and give equal 
weight to both models.\37\ However, contrary to the proposal in the 
Briefing Orders, the Commission declined to use either the Expected 
Earnings analysis or Risk Premium model.\38\ The Commission also made 
findings as to the DCF model and the CAPM and adopted specific low and 
high-end outlier tests.
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    \35\ Opinion No. 569, 169 FERC ] 61,129 at P 18.
    \36\ Id. PP 1, 18.
    \37\ Id. PP 276, 425.
    \38\ Id. PP 18, 31, 200, 340.
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3. Opinion No. 569-A
    15. In Opinion No. 569-A, the Commission modified the methodology 
established in Opinion No. 569 in several respects. First, as to the 
DCF model, the Commission reduced the weighting of the long-term growth 
projection from one-third to 20% and modified the high-end outlier test 
adopted in Opinion No. 569.\39\ Second, as to the CAPM, the Commission 
clarified that it will modify the high-end outlier test adopted in 
Opinion No. 569 \40\ and that it will consider, based on evidence 
provided in future proceedings, use of Value Line data, instead of IBES 
data, as the source of the short-term growth projection in the DCF 
component of the CAPM.\41\ Third, the Commission adopted a modified 
version of the Risk Premium model.\42\ The Commission explained that it 
would afford equal weighting to the DCF, CAPM, and Risk Premium 
analyses and denied requests for rehearing of its decision to exclude 
Expected Earnings.\43\
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    \39\ Opinion No. 569-A, 171 FERC ] 61,154 at PP 57, 154.
    \40\ Id. P 154.
    \41\ Id. P 78.
    \42\ Id. PP 104-114.
    \43\ Id. P 141.
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D. NOI

    16. In the NOI, the Commission requested comment on whether uniform 
application of the Commission's base ROE policy across the electric, 
natural gas pipeline, and oil pipeline industries is appropriate and 
advisable \44\ and whether the Commission, if it departed from its sole 
use of a two-step DCF methodology for public utilities, should also use 
its new method or methods to determine natural gas and oil pipeline 
ROEs.\45\ The Commission also sought comment on its guidelines for 
proxy group formation, including proxy group screening criteria and 
appropriate high and low-end outlier tests.\46\
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    \44\ NOI, 166 FERC ] 61,207 at P 29.
    \45\ Id. P 32.
    \46\ Id. P 34.
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    17. Numerous entities and individuals submitted comments in 
response to the NOI. Below, we discuss the comments that are relevant 
to the revised policy for natural gas and oil pipeline ROE 
methodologies that we adopt herein.

II. Discussion

    18. Upon review of the comments and based on the Commission's 
findings in Opinion Nos. 569 and 569-A, we revise our policy for 
determining natural gas and oil pipeline ROEs. Under this revised 
policy, we will (1) determine ROE by averaging the results of DCF and 
CAPM analyses while retaining the existing two-thirds/one-third 
weighting of the short and long-term growth projections in the DCF; (2) 
give equal weight to the DCF and CAPM analyses; (3) consider using 
Value Line data as the source of the short-term growth projection in 
the CAPM; (4) consider proposals to include Canadian companies in 
pipeline proxy groups while continuing to apply our proxy group 
criteria flexibly until sufficient proxy group members are obtained; 
(5) exclude Risk Premium and Expected Earnings analyses; and (6) 
continue to address outliers in pipeline proxy groups on a case-by-case 
basis and refrain from applying specific outlier tests.
    19. We are not persuaded to adopt any additional policy changes at 
this time and will address all other issues concerning the 
determination of natural gas and oil pipeline ROEs as they arise in 
future proceedings.

A. Revised Policy for Determining Natural Gas and Oil Pipeline ROEs

1. Use of the DCF and CAPM
a. Background
    20. In the Briefing Orders, the Commission preliminarily found that 
since it began relying primarily on the DCF model to determine ROE in 
the 1980s, investors have increasingly used a diverse set of data 
sources and models to inform their investment decisions.\47\ Because 
investors consider more than one financial model when making investment 
decisions, the Commission reasoned that relying on multiple models 
makes it more likely that the Commission's decision will accurately 
reflect how investors are making their

[[Page 31763]]

investment decisions.\48\ The Commission later determined in 
Trailblazer that investor reliance on multiple methodologies presumably 
applies to investments in natural gas pipelines as well as public 
utilities.\49\
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    \47\ Coakley Briefing Order, 165 FERC ] 61,030 at P 40; MISO 
Briefing Order, 165 FERC ] 61,118 at P 42.
    \48\ See Coakley Briefing Order, 165 FERC ] 61,030 at PP 36, 44; 
MISO Briefing Order, 165 FERC ] 61,118 at PP 38, 46.
    \49\ Trailblazer, 166 FERC ] 61,141 at P 48.
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    21. The Commission departed from sole reliance on the DCF model for 
public utilities in Opinion No. 569, finding that investors have 
varying preferences as to which of the various methods for determining 
cost of equity they may use to inform their investment decisions and 
that the DCF and CAPM are among the primary methods that investors use 
for this purpose.\50\ Thus, the Commission concluded that expanding its 
methodology for determining public utility ROEs to use the CAPM in 
addition to the DCF model will make it more likely that its decisions 
will accurately reflect how investors make their investment decisions 
and produce cost-of-equity estimates that more accurately reflect what 
ROE a utility must offer to attract capital.\51\ The Commission further 
explained that using the CAPM will also mitigate the model risk that 
the DCF model may perform poorly in certain circumstances.\52\
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    \50\ Opinion No. 569, 169 FERC ] 61,129 at PP 34, 171.
    \51\ Id. PP 31, 34, 452.
    \52\ Id. PP 39, 171.
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b. NOI Comments
    22. Commenters are divided on whether the Commission should expand 
its methodology for determining natural gas and oil pipeline ROEs to 
consider multiple models. Commenters representing natural gas and oil 
pipeline shipper interests \53\ urge the Commission to continue relying 
solely on the DCF model to determine pipeline ROEs.\54\ These 
commenters contend that the DCF model is a standardized approach that 
promotes predictability for pipelines and shippers and assert that 
there is no reason to consider additional models.\55\
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    \53\ These commenters include: Airlines for America; Liquids 
Shippers Group; Natural Gas Supply Association (NGSA); American 
Public Gas Association (APGA); Process Gas Consumers Group and 
American Forest & Paper Association (PGC/AF&PA); and the Canadian 
Association of Petroleum Producers (CAPP).
    \54\ Airlines for America Initial Comments at 5-7; Liquids 
Shippers Group Initial Comments at 12-17, 22-25; NGSA Initial 
Comments at 3-6, 25, 27; APGA Comments at 3; PGC/AF&PA Joint 
Comments at 1-2, 6-8; see also CAPP Initial Comments at 27-28 
(lauding the DCF as superior and stating that investors most likely 
view the CAPM as a supplementary model).
    \55\ Airlines for America Initial Comments at 1-2, 5-7; Liquids 
Shippers Group Initial Comments at 12-17; NGSA Initial Comments at 
3-4, 10, 25; PGC/AF&PA Joint Comments at 6-8.
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    23. In contrast, natural gas and oil pipelines and trade 
associations \56\ argue that it would be reasonable to consider other 
models in addition to the DCF, subject to modifications in recognition 
of the unique risks and regulatory framework applicable to the natural 
gas and oil pipeline industries.\57\ Generally, these entities contend 
that the Commission's findings that investors rely upon multiple 
financial models in making investment decisions also apply to investors 
in pipelines.\58\
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    \56\ These commenters include: Association of Oil Pipe Lines 
(AOPL); Interstate Natural Gas Association of America (INGAA); 
Magellan Midstream Partners, L.P., Plains Pipeline L.P.; SFPP, L.P. 
and Calnev Pipe Line LLC; and Tallgrass Energy, LP.
    \57\ AOPL Initial Comments at 3, 8-9, 11-12; INGAA Initial 
Comments at 40-41; Magellan Initial Comments at 8-13; Plains 
Comments at 3-4; SFPP-Calnev Comments at 3-4; Tallgrass Initial 
Comments at 1, 11.
    \58\ E.g., AOPL Initial Comments at 4, 11; Tallgrass Initial 
Comments at 2.
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c. Commission Determination
    24. Based on the Commission's findings in Opinion No. 569, we 
revise our methodology for determining natural gas and oil pipeline 
ROEs to rely on multiple financial models, rather than relying solely 
on the DCF model. Specifically, we will determine pipeline ROEs using 
the DCF model and CAPM, but in contrast to our methodology for public 
utilities, we will not use the Risk Premium model.
    25. As an initial matter, we note that the D.C. Circuit has 
repeatedly observed that the Commission is not required to rely upon 
the DCF model alone or even at all.\59\ As such, the Commission may 
``change its past practices,'' such as relying exclusively on the DCF 
model, ``with advances in knowledge in its given field or as its 
relevant experience and expertise expands,'' provided that it supplies 
``a reasoned analysis indicating that prior policies and standards are 
being deliberately changed, not casually ignored.'' \60\
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    \59\ E.g., Tenn. Gas Pipeline Co. v. FERC, 926 F.2d 1206, 1211 
(D.C. Cir. 1991) (explaining that the Commission is free to reject 
the DCF, provided that it adequately explains its reasons for doing 
so); NEPCO Mun. Rate Comm. v. FERC, 668 F.2d 1327, 1345 (D.C. Cir. 
1981) (``FERC is not bound `to the service of any single formula or 
combination of formulas.' '' (quoting FPC v. Nat. Gas Pipeline Co. 
of Am., 315 U.S. 575, 586 (1942))).
    \60\ Opinion No. 569, 169 FERC ] 61,129 at P 32 (quoting Nuclear 
Energy Inst., Inc. v. EPA, 373 F.3d 1251, 1296 (D.C. Cir. 2004) (per 
curiam)) (internal citations and quotation marks omitted).
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    26. In Hope, the Supreme Court held that ``the return to the equity 
owner should be commensurate with returns on investments in other 
enterprises having corresponding risks. That return, moreover, should 
be sufficient to assure confidence in the financial integrity of the 
enterprise, so as to maintain its credit and to attract capital.'' \61\ 
Thus, a key consideration in determining just and reasonable utility 
ROEs is determining what ROE an entity must offer in order to attract 
capital, i.e., induce investors to invest in the entity in light of its 
risk profile.\62\ As the Commission stated in Opinion No. 414-B,\63\ 
``the cost of common equity to a regulated enterprise depends upon what 
the market expects not upon precisely what is going to happen.'' \64\ 
Thus, in determining what ROE to award a utility, we must look to how 
investors analyze and compare their investment opportunities.
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    \61\ Hope, 320 U.S. at 603; see also CAPP v. FERC, 254 F.3d at 
293 (``In order to attract capital, a utility must offer a risk-
adjusted expected rate of return sufficient to attract 
investors.'').
    \62\ See Bluefield Waterworks & Improvement Co. v. Pub. Serv. 
Comm'n of W. Va., 262 U.S. 679, 692-93 (1923) (discussing factors an 
investor considers in making investment decisions).
    \63\ Transcontinental Gas Pipe Line Corp., Opinion No. 414-B, 85 
FERC ] 61,323 (1998).
    \64\ Opinion No. 414-B, 85 FERC at 62,268; see also Kern River 
Gas Transmission Co., Opinion No. 486-B, 126 FERC ] 61,034, at P 120 
(2009), order on reh'g and compliance, Opinion No. 486-C, 129 FERC ] 
61,240 (2009).
---------------------------------------------------------------------------

    27. We find that the rationale set forth in the Briefing Orders and 
Opinion No. 569 for relying on CAPM in addition to the DCF applies 
equally to natural gas and oil pipelines. In those proceedings, the 
Commission found that investors employ various methods for determining 
cost of equity and that the DCF and CAPM are among the primary methods 
investors use for this purpose.\65\ In addition, the Commission found 
in Opinion No. 569 that both record evidence and academic literature 
\66\ indicated that CAPM is

[[Page 31764]]

widely used by investors.\67\ These findings apply to investors 
generally, and we do not see, nor do the NOI comments identify, any 
basis for distinguishing between investors in public utilities and 
investors in natural gas and oil pipelines in this context. We 
therefore find that investors in pipelines, like investors in public 
utilities, consider multiple models for measuring cost of equity, 
including the DCF model and CAPM, in making investment decisions.\68\
---------------------------------------------------------------------------

    \65\ Opinion No. 569, 169 FERC ] 61,129 at PP 34, 236; Coakley 
Briefing Order, 165 FERC ] 61,030 at P 35; MISO Briefing Order, 165 
FERC ] 61,118 at P 37.
    \66\ See, e.g., Jonathan B. Berk and Jules H. van Binsbergen, 
Assessing Asset Pricing Models Using Revealed Preference, 119(1) 
Journal of Financial Economics 1, 2 (2016) (``We find that the CAPM 
is the closest model to the model that investors use to make their 
capital allocation decisions . . . investors appear to be using the 
CAPM to make their investment decisions.''); Brad M. Barber, et al., 
Which Factors Matter to Investors? Evidence from Mutual Fund Flows, 
29(10) The Review of Financial Studies 2600, 2639 (2016) (``[W]hen 
we ran a horse race between six asset-pricing models, the CAPM is 
able to best explain variation in flows across mutual funds.''); id. 
at 2624 (``[T]he CAPM does the best job of predicting fund-flow 
relations.''); see also John R. Graham and Campbell R. Harvey, The 
Theory and Practice of Corporate Finance: Evidence from the Field, 
60(2) Journal of Financial Economics 187, 201 (2001) (explaining 
that ``the CAPM is by far the most popular method of estimating the 
cost of equity capital.'').
    \67\ Opinion No. 569, 169 FERC ] 61,129 at P 236.
    \68\ See Trailblazer, 166 FERC ] 61,141 at P 48 (citing Coakley 
Briefing Order, 165 FERC ] 61,030 at PP 34-36). We note that with 
the exception of commenters supporting sole reliance on the DCF 
model, commenters generally do not oppose use of the CAPM for 
natural gas and oil pipelines. See CAPP Initial Comments at 28; 
INGAA Initial Comments at 41 (supporting use of DCF, CAPM, and 
Expected Earnings); AOPL Initial Comments at 8-9 (endorsing use of 
the proposed four-model methodology, which includes CAPM, as a 
reasonable approach for oil pipelines); Plains Comments at 4 (same); 
SFPP-Calnev Comments at 4 (same).
---------------------------------------------------------------------------

    28. Accordingly, under the rationale set forth in Opinion No. 569, 
we will expand our methodology for determining natural gas and oil 
pipeline ROEs and will consider the CAPM in addition to the DCF 
model.\69\ We conclude that as with public utilities, expanding the 
methodology we use to determine ROE for natural gas and oil pipelines 
to include the CAPM in addition to the DCF model will better reflect 
how investors in those industries measure cost of equity while tending 
to reduce the model risk associated with relying on the DCF model 
alone. This should result in our ROE analyses producing cost-of-equity 
estimates for natural gas and oil pipelines that more accurately 
reflect what ROE a pipeline must offer in order to attract capital.
---------------------------------------------------------------------------

    \69\ Opinion No. 569, 169 FERC ] 61,129 at P 236.
---------------------------------------------------------------------------

2. DCF
    29. We decline to adopt any changes to the two-step DCF model that 
we apply to natural gas and oil pipelines under our existing policy. We 
will therefore continue to base the long-term growth projection on 
forecasts of long-term growth of GDP, adjust the long-term growth 
projection of MLPs to equal 50% of GDP consistent with the 2008 Policy 
Statement,\70\ and use only the short-term growth projection for 
purposes of the (1+.5g) adjustment to dividend yield. As discussed 
below, in contrast to our revised base ROE methodology for public 
utilities as adopted in Opinion No. 569-A, we will retain the existing 
two-thirds/one-third weighting for the short and long-term growth 
projections.
---------------------------------------------------------------------------

    \70\ The Commission adopted the 50% long-term growth rate 
adjustment for MLPs in the 2008 Policy Statement in part because 
MLPs have limited investment opportunities and face pressure to 
maintain a high payout ratio. See 2008 Policy Statement, 123 FERC ] 
61,048 at PP 95-96. Commenters state that MLPs no longer face the 
same pressure to maintain a high payout ratio and often now generate 
growth internally through retained earnings, which will cause their 
growth rates to increase. See, e.g., INGAA Initial Comments at 58-
59. While the Commission continues to favor the 50% long-term growth 
adjustment for MLPs, parties may present empirical evidence for an 
alternative adjustment in cost-of-service rate proceedings. Natural 
gas and oil pipelines that are MLPs may not use alternative 
adjustments to support their annual forms.
---------------------------------------------------------------------------

a. NOI Comments
    30. Commenters that address the weighting of the growth projections 
in the DCF model are divided on whether the Commission should retain 
the existing weighting, with AOPL and NGSA not proposing any 
adjustments \71\ and CAPP and INGAA proposing alternative weighting 
schemes. CAPP contends that the Commission should accord the growth 
projections equal weighting.\72\ INGAA, on the other hand, proposes to 
increase the weighting of the short-term projection to four-fifths and 
reduce the weighting of the long-term projection to one-fifth.\73\
---------------------------------------------------------------------------

    \71\ AOPL Initial Comments at 41; NGSA Initial Comments at 32-
33; see also Magellan Initial Comments at 23-24 (supporting two-
thirds/one-third weighting should Commission retain existing two-
step DCF).
    \72\ CAPP Initial Comments at 40.
    \73\ INGAA Initial Comments at 55.
---------------------------------------------------------------------------

b. Commission Determination
    31. The D.C. Circuit has recognized that the Commission has 
discretion regarding its growth projection weighting choices.\74\ 
Although the Commission is reducing the weighting of the long-term 
growth projection in public utility proceedings to one-fifth, we find 
that distinctions between public utilities and natural gas and oil 
pipelines support exercising this discretion to continue affording one-
third weighting to the long-term growth projections in our analyses of 
pipeline ROEs.
---------------------------------------------------------------------------

    \74\ See CAPP v. FERC, 254 F.3d at 297 (holding that the 
Commission did not abuse its discretion in reducing the weighting of 
the long-term growth projection from one-half to one-third).
---------------------------------------------------------------------------

    32. The Commission adopted the existing two-thirds/one-third 
weighting scheme in Opinion No. 414-A.\75\ As explained in Opinion No. 
569-A, reducing the weighting of the long-term growth projection in DCF 
analyses of public utilities is appropriate because the short-term 
growth projections of public utilities have declined relative to GDP 
since the issuance of Opinion No. 414-A.\76\ As a result, investors may 
reasonably consider current public utility short-term growth 
projections to be more sustainable than when the Commission adopted the 
existing weighting policy in 1998. It is therefore reasonable to afford 
greater weight to the short-term growth projection and lesser weight to 
the long-term growth projection in determining cost of equity for 
public utilities.\77\
---------------------------------------------------------------------------

    \75\ Opinion No. 414-A, 84 FERC ] 61,084 (1998).
    \76\ In Opinion No. 414-A, the short-term growth projections of 
the proxy group members averaged 11.33%, almost twice the long-term 
GDP growth projection of 5.45%. See id. at app. A. As explained in 
Opinion No. 569-A, the average short-term growth projections for the 
proxy group in one of the public utility proceedings addressed 
therein had declined to 5.03%, as compared to a long-term GDP growth 
projection in that proceeding of 4.39%. Opinion No. 569-A, 171 FERC 
] 61,154 at P 57.
    \77\ Opinion No. 569-A, 171 FERC ] 61,154 at PP 57-58.
---------------------------------------------------------------------------

    33. This reasoning does not apply with equal force to natural gas 
and oil pipelines. Although the short-term growth projections of 
natural gas and oil pipelines are lower than in 1998, they have not 
declined to the same extent as those of public utilities.\78\ As such, 
investors could reasonably view pipelines' short-term growth 
projections as less sustainable than the projections of public 
utilities. Moreover, the shale gas revolution has caused the natural 
gas and oil pipeline industries to become more dynamic and less mature, 
which could undermine the reliability of pipelines' short-term growth 
projections.
---------------------------------------------------------------------------

    \78\ For example, using data from February 2020, the short-term 
growth projections of a hypothetical natural gas pipeline proxy 
group consisting of Enbridge Inc., TC Energy, National Fuel Gas 
Company, Kinder Morgan Inc., and Williams Companies, Inc., average 
5.92% relative to a GDP growth projection of 4.22%. By comparison, 
in one of the public utility proceedings addressed in Opinion No. 
569-A, the short-term growth projections of the proxy group averaged 
5.03% relative to a projected growth in GDP of 4.39%. Id. P 57.
---------------------------------------------------------------------------

    34. For these reasons, we exercise our discretion to maintain our 
existing weighting scheme and will continue to accord two-thirds 
weighting to the short-term growth projection and one-third weighting 
to the long-term growth projection in natural gas and oil pipeline 
proceedings.
3. CAPM
    35. We now turn to how we will apply the CAPM to natural gas and 
oil pipelines. As discussed below, with regard to the calculation of 
the market risk premium and the use of Value Line adjusted betas in 
pipeline proceedings, we adopt the policy established in Opinion No. 
569.

[[Page 31765]]

a. Calculation of Market Risk Premium
    36. As described above, the CAPM market risk premium is calculated 
by subtracting the risk-free rate, which is typically represented by a 
proxy such as the yield on 30-year U.S. Treasury bonds, from the 
expected market return. The expected market return can be estimated 
either using a backward-looking approach based upon realized market 
returns during a historical period, a forward-looking approach applying 
the DCF model to a representative market index, such as the S&P 500, or 
a survey of academic and investment professionals.\79\
---------------------------------------------------------------------------

    \79\ Opinion No. 569, 169 FERC ] 61,129 at P 239 (citing Morin 
at 155-162).
---------------------------------------------------------------------------

i. Background
    37. In Opinion No. 569, the Commission adopted the use of the 30-
year U.S. Treasury average historical bond yield over a six-month 
period as the risk-free rate.\80\ The Commission explained that the 
six-month period should correspond as closely as possible to the six-
month financial study period used to produce the DCF study in the 
applicable proceeding.\81\ For the expected market return, the 
Commission adopted a forward-looking approach based upon a one-step DCF 
analysis of the dividend paying members of the S&P 500.\82\ The 
Commission rejected proposals to use a two-step DCF analysis for this 
purpose, finding that the rationale for incorporating a long-term 
growth projection in conducting a two-step DCF analysis of a specific 
group of utilities does not apply when conducting a DCF study of the 
companies in the S&P 500 because (i) the S&P 500 is regularly updated 
to ensure that it only includes companies with high market 
capitalization and remains representative of the industries in the 
economy of the United States and (ii) the dividend paying members of 
the S&P 500 constitute a large portfolio of stocks and therefore 
include companies at all stages of growth.\83\ Furthermore, the 
Commission found that S&P 500 companies with growth rates that are 
negative or in excess of 20% should be excluded from the CAPM analysis 
\84\ and approved the use of a size premium adjustment in the CAPM 
analysis.\85\ The Commission affirmed these conclusions on 
rehearing.\86\
---------------------------------------------------------------------------

    \80\ Id. P 237.
    \81\ Id. PP 237-238.
    \82\ Id. P 260. Because the rationale for including a long-term 
growth estimate in the DCF analysis of a specific utility does not 
apply to the DCF analysis of a broad, representative market index 
with a wide variety of companies that is regularly updated, the 
Commission held that the DCF analysis of the dividend paying members 
of the S&P 500 should be a one-step DCF analysis that uses only 
short-term growth projections. Id. PP 261-266.
    \83\ Id. PP 263-265.
    \84\ Id. PP 267-268.
    \85\ Id. PP 296-303.
    \86\ Opinion No. 569-A, 171 FERC ] 61,154 at PP 75-77, 85.
---------------------------------------------------------------------------

ii. NOI Comments
    38. INGAA, CAPP, and NGSA address how the Commission should 
determine the CAPM market risk premium in pipeline proceedings. 
Regarding the risk-free rate, INGAA states that although the Commission 
could use either the 20-year or 30-year U.S. Treasury bond rate, it 
supports using the 20-year rate.\87\ As to the expected market return, 
INGAA supports using a one-step DCF analysis of dividend paying 
companies in the S&P 500.\88\ CAPP and NGSA, by contrast, support using 
a two-step DCF analysis that uses both short-term and long-term growth 
rates.\89\
---------------------------------------------------------------------------

    \87\ INGAA Initial Comments at 61. INGAA states that unlike 30-
year bonds, which were not issued for a period of time, 20-year bond 
yields are available back to 1926 and will therefore allow the use 
of a full historical data set covering a longer period. Id.
    \88\ Id. (citing Ass'n of Bus. Advocating Tariff Equity v. 
Midcontinent Indep. Sys. Operator, Inc., Opinion No. 551, 156 FERC ] 
61,234, at PP 166-168 (2016)).
    \89\ CAPP Initial Comments at 41; NGSA Initial Comments at 33.
---------------------------------------------------------------------------

iii. Commission Determination
    39. We adopt the policy established in Opinion No. 569. Thus, in 
determining the CAPM market risk premium for natural gas and oil 
pipelines, we will (1) use, as the risk-free rate, the 30-year U.S. 
Treasury average historical bond yield over a six-month period 
corresponding as closely as possible to the six-month financial study 
period used to produce the DCF study in the applicable proceeding, (2) 
estimate the expected market return using a forward-looking approach 
based on a one-step DCF analysis of all dividend paying companies in 
the S&P 500,\90\ and (3) exclude S&P 500 companies with growth rates 
that are negative or in excess of 20%.
---------------------------------------------------------------------------

    \90\ The appropriate data source for the short-term growth 
projection in the DCF component of the CAPM is addressed infra.
---------------------------------------------------------------------------

    40. First, as the Commission recognized in Opinion No. 531-B, 30-
year U.S. Treasury bond yields are a generally accepted proxy for the 
risk-free rate in a CAPM analysis.\91\ We are not persuaded to adopt 
INGAA's proposal to use the 20-year U.S. Treasury bond yield for this 
purpose. The Commission determined in Opinion No. 569 that factors 
supporting the use of the 30-year U.S. Treasury average historical bond 
yield over a six-month period outweigh factors supporting the use of 
the 20-year U.S. Treasury yield, including any potential benefit that 
may come from using a data set covering a longer period.\92\ We affirm 
that conclusion here.
---------------------------------------------------------------------------

    \91\ Opinion No. 531-B, 150 FERC ] 61,165 at P 114 (citing Morin 
at 151-152).
    \92\ Opinion No. 569, 169 FERC ] 61,129 at P 237.
---------------------------------------------------------------------------

    41. Second, we will determine the expected market return using a 
one-step DCF analysis of the dividend paying members of the S&P 500. As 
explained in Opinion No. 569, using a DCF analysis of the dividend 
paying members of the S&P 500 is a well-recognized method of estimating 
the expected market return for purposes of the CAPM,\93\ and we find 
that this method is likewise reasonable for purposes of applying the 
CAPM to natural gas and oil pipelines. We also find that the reasons 
set forth in Opinion No. 569 for using a one-step DCF analysis, instead 
of a two-step analysis, in estimating the expected market return are 
equally valid in the context of natural gas and oil pipelines.\94\ 
Accordingly, for the reasons stated in Opinion No. 569,\95\ we will use 
a one-step DCF analysis of the dividend paying companies in the S&P 500 
as the expected market return in applying the CAPM under our revised 
ROE methodology for natural gas and oil pipelines.
---------------------------------------------------------------------------

    \93\ Id. P 260.
    \94\ Id. PP 262-266.
    \95\ See id. PP 260-276.
---------------------------------------------------------------------------

    42. Third, consistent with Opinion No. 569, we will screen from the 
CAPM analysis of natural gas and oil pipelines S&P 500 companies with 
growth rates that are negative or in excess of 20%. The Commission has 
explained that such low or high growth rates are highly unsustainable 
and unrepresentative of the growth rates of public utilities.\96\ We 
find that these growth rates are likewise not representative of 
sustainable growth rates for companies in pipeline proxy groups. We 
will therefore apply this growth rate screen as part of the CAPM 
analysis in natural gas and oil pipeline proceedings.
---------------------------------------------------------------------------

    \96\ Id. P 268.
---------------------------------------------------------------------------

b. Betas and Size Premium
i. Background
    43. The Commission found in Opinion Nos. 569 and 569-A that Value 
Line adjusted betas are reasonable for use in the CAPM analysis for 
public utilities.\97\ The Commission explained that there was 
substantial evidence that investors rely on Value Line betas and

[[Page 31766]]

observed that Dr. Morin supports the use of adjusted betas in the CAPM.
---------------------------------------------------------------------------

    \97\ Id. P 297; Opinion No. 569-A, 171 FERC ] 61,154 at PP 75-
76.
---------------------------------------------------------------------------

    44. Moreover, the Commission also accepted the use of a size 
premium adjustment derived using Duff & Phelps raw betas based on a 
regression of the monthly returns on the stock index that are in excess 
of a 30-year U.S. Treasury yield over the period of 1926 through the 
most recent period.\98\ The Commission affirmed that the use of such an 
adjustment was ``a generally accepted approach to CAPM analyses'' and 
determined that application of size premium adjustments based on the 
New York Stock Exchange (NYSE) to dividend paying members of the S&P 
500 is acceptable.\99\ The Commission acknowledged that there is 
imperfect correspondence between the size premia being developed with 
different betas, but concluded that the size premium adjustments 
improve the accuracy of CAPM results and cause the CAPM to better 
correspond to the cost-of-capital estimates used by investors.\100\ The 
Commission also found that sufficient academic literature exists to 
indicate that many investors rely on size premia.\101\
---------------------------------------------------------------------------

    \98\ Opinion No. 569, 169 FERC ] 61,129 at PP 279, 296.
    \99\ Id. P 296 (quoting Opinion No. 531-B, 150 FERC ] 61,165 at 
P 117).
    \100\ Id. P 298.
    \101\ Id. PP 299-300.
---------------------------------------------------------------------------

ii. NOI Comments
    45. A variety of commenters, including AOPL, INGAA, Magellan, CAPP, 
and NGSA, support use of Value Line adjusted betas in applying the 
CAPM.\102\ INGAA adds that although Value Line betas, which are based 
on five years of historical data, may be appropriate in most cases, it 
is possible that using betas based on five years of data may not 
reflect more recent events that have substantially changed the risk 
characteristics of the natural gas pipeline industry. INGAA therefore 
states that in such circumstances, the Commission should consider beta 
estimates calculated over shorter periods.\103\
---------------------------------------------------------------------------

    \102\ AOPL Initial Comments at 42; INGAA Initial Comments at 62; 
Magellan Initial Comments at 27; CAPP Initial Comments at 42; NGSA 
Comments at 34; see also Maryland Office of People's Counsel 
(Maryland OPC) Initial Comments at 21-22 (``Value Line is the most 
detailed and most trusted investment source currently available in 
the industry. The Value Line beta is calculated over a long-term 
time period that dampens volatility and, as such, is the most 
representative source now available in the marketplace.'').
    \103\ INGAA Initial Comments at 62.
---------------------------------------------------------------------------

iii. Commission Determination
    46. We adopt the reasoning in Opinion Nos. 569 and 569-A and find 
reasonable the use of Value Line adjusted betas in the CAPM analysis as 
applied to natural gas and oil pipelines. As the Commission has 
explained, there is substantial evidence indicating that investors rely 
on Value Line betas in making their investment decisions, and this 
finding presumably applies equally to investors in natural gas and oil 
pipelines. Although we recognize that the distinct risks facing 
interstate natural gas and oil pipelines may in some cases bear upon 
whether an alternative beta source would be more appropriate, we will 
address such issues as they arise in specific proceedings.
    47. Likewise, we find reasonable the use of the size premium 
adjustment based on the NYSE, as discussed in Opinion Nos. 531-B \104\ 
and 569.\105\ The use of such adjustments is ``a generally accepted 
approach to CAPM analyses'' that improves the accuracy of the CAPM 
results and causes such results to better correspond to the cost-of-
capital estimates that investors use in making investment 
decisions.\106\ As such, we find that use of these adjustments will 
improve the accuracy of cost-of-equity estimates for natural gas and 
oil pipelines under our revised ROE methodology.
---------------------------------------------------------------------------

    \104\ Opinion No. 531-B, 150 FERC ] 61,165 at P 117.
    \105\ Opinion No. 569, 169 FERC ] 61,129 at P 296.
    \106\ Id. PP 296-297 (quoting Opinion No. 531-B, 150 FERC ] 
61,165 at P 117).
---------------------------------------------------------------------------

4. Weighting of Models
a. Background
    48. In Opinion No. 569, the Commission held that it would give 
equal weight to the DCF model and CAPM in analyzing ROE for public 
utilities.\107\ The Commission found that the evidence indicated that 
neither model was conclusively superior to the other and reasoned that 
giving each model equal weight will reduce the model risk associated 
with any particular model more than giving one model greater weight 
than the other.\108\ After expanding its public utility base ROE 
methodology in Opinion No. 569-A to include the Risk Premium model, the 
Commission held that it would accord equal weight to all three 
models.\109\
---------------------------------------------------------------------------

    \107\ Id. PP 425, 427.
    \108\ Id. P 426.
    \109\ Opinion No. 569-A, 171 FERC ] 61,154 at P 141.
---------------------------------------------------------------------------

b. NOI Comments
    49. Commenters propose various approaches to weighting the models 
used to determine ROE. CAPP states that the Commission should give the 
DCF model at least 50% weighting while giving the remaining weight to 
any other models the Commission decides to use.\110\ The Maryland OPC 
states that if the Commission uses multiple models, it should accord 
the DCF model the majority of the weighting while giving the other 
models a minority weighting.\111\ INGAA and Tallgrass oppose equal 
weighting and assert that the Commission should adopt a flexible 
weighting approach that allows it to exclude or give appropriate weight 
to any model in light of prevailing financial conditions and the facts 
and circumstances of each case.\112\ The New York State Public Service 
Commission (NYPSC) submits that the Commission should give two-thirds 
weighting to the DCF model and one-third weighting to the CAPM.\113\
---------------------------------------------------------------------------

    \110\ CAPP Initial Comments at 30.
    \111\ Maryland OPC Initial Comments at 12.
    \112\ INGAA Initial Comments at 8-9; Tallgrass Initial Comments 
at 12.
    \113\ NYPSC Initial Comments at 18.
---------------------------------------------------------------------------

c. Commission Determination
    50. We adopt the rationale of Opinion Nos. 569 and 569-A and will 
give equal weight to the DCF model and CAPM in determining natural gas 
and oil pipeline ROEs. As stated in Opinion No. 569, we find that 
neither the DCF model nor the CAPM is conclusively superior and that 
giving both models equal weight will mitigate the risks associated with 
the potential errors or flaws in any one model. The comments proposing 
alternative weighting schemes do not refute these concerns and are 
therefore unpersuasive.
5. Data Sources
a. Background
    51. The Commission has historically preferred IBES data as the 
source of the short-term growth projection in the DCF model.\114\ By 
contrast, because less precision was required of the CAPM when the 
Commission used it only to corroborate the results of the DCF analysis, 
the Commission allowed parties to average IBES and Value Line growth 
projections in the DCF component of the CAPM.\115\
---------------------------------------------------------------------------

    \114\ E.g., Nw. Pipeline Corp., 92 FERC ] 61,287, at 62,001-02 
(2000) (quoting Opinion No. 396-B, 79 FERC at 62,385).
    \115\ Opinion No. 551, 156 FERC ] 61,234 at P 169.
---------------------------------------------------------------------------

    52. In Opinion 569, the Commission affirmed that it would use IBES 
projections as the sole source of the short-term growth projections in 
the DCF model.\116\ The Commission also required the sole use of IBES 
projections for the DCF component of the CAPM, explaining that because 
it would be weighting the CAPM equally with the

[[Page 31767]]

DCF model in setting just and reasonable ROEs, the CAPM must be 
implemented with the same degree of precision as the DCF model.\117\ 
The Commission explained that IBES data was preferable to Value Line 
data because unlike Value Line projections, which represent the 
estimates of a single analyst at a single institution, IBES projections 
generally represent consensus growth estimates by a number of analysts 
from different firms.\118\ In addition, the Commission noted that IBES 
growth projections are generally timelier than the Value Line 
projections because IBES updates its database on a daily basis as 
participating analysts revise their forecasts, whereas Value Line 
publishes its projections on a rolling quarterly basis.\119\
---------------------------------------------------------------------------

    \116\ Opinion No. 569, 169 FERC ] 61,129 at P 120.
    \117\ Id. P 276.
    \118\ Id. P 125.
    \119\ Id. P 128.
---------------------------------------------------------------------------

    53. In Opinion No 569-A, the Commission affirmed its preference for 
IBES data for the short-term growth projection in the DCF model but 
granted rehearing of its decision to require sole use of IBES data for 
the DCF component of the CAPM.\120\ Acknowledging its concerns about 
Value Line data as discussed in Opinion No. 569, the Commission 
nonetheless concluded that use of these estimates will bring value to 
its revised ROE methodology. The Commission found that although Value 
Line estimates come from a single analyst, they include the input of 
multiple analysts because they are vetted through internal processes 
including review by a committee composed of peer analysts. Similarly, 
the Commission found that there is value in including Value Line 
estimates because they are updated on a more predictable basis than 
IBES estimates. The Commission therefore concluded that IBES and Value 
Line growth estimates both have advantages and that it is appropriate 
to consider both data sources in determining public utility ROEs. In 
light of the Commission's longstanding use of IBES data in the DCF 
model, the Commission determined that it was appropriate to consider 
using Value Line in the newly adopted CAPM.
---------------------------------------------------------------------------

    \120\ Opinion No. 569-A, 171 FERC ] 61,154 at PP 78-83.
---------------------------------------------------------------------------

b. NOI Comments
    54. Commenters are divided on the data source the Commission should 
use for the short-term growth projection in pipeline proceedings. AOPL 
states that the Commission should allow oil pipelines to use Value Line 
projections because they do not overlap with or duplicate IBES 
projections.\121\ INGAA likewise supports use of Value Line growth 
estimates to supplement the IBES three to five-year growth 
projections.\122\ In contrast, Magellan, NGSA, and CAPP support the 
sole use of IBES growth forecasts, with CAPP asserting that Value Line 
is inferior to IBES because it reflects the estimate of a single 
analyst.\123\
---------------------------------------------------------------------------

    \121\ AOPL Initial Comments at 38.
    \122\ INGAA Initial Comments, Attachment A at 28-33 (Affidavit 
of Dr. Michael J. Vilbert).
    \123\ Magellan Initial Comments at 20; NGSA Initial Comments at 
29-30; CAPP Initial Comments at 36-37, 39.
---------------------------------------------------------------------------

c. Commission Determination
    55. With regard to the short-term growth projections in our DCF and 
CAPM analyses of natural gas and oil pipelines, we adopt the policy set 
forth in Opinion No. 569-A. Therefore, in natural gas and oil pipeline 
proceedings we will (1) continue to prefer use of IBES three to five-
year growth projections as the short-term growth projection in the two-
step DCF analysis and (2) allow participants to propose using Value 
Line growth projections as the source of the short-term growth 
projection in the one-step DCF analysis embedded within the CAPM.
    56. We reiterate our belief that both IBES and Value Line growth 
estimates have advantages and that it is appropriate to include both 
data sources in determining ROEs. As in public utility proceedings, it 
is beneficial to diversify the data sources used in our revised natural 
gas and oil pipeline ROE methodology because doing so may better 
reflect the data sources that investors consider and mitigate the 
effect of any unusual data in either source. Although we have not 
previously used Value Line growth estimates in determining natural gas 
and oil pipeline ROEs, we believe that including these estimates in our 
methodology will bring value to our analysis because they are updated 
on a more predictable basis than IBES estimates and reflect the 
consensus growth estimates of multiple analysts. By contrast, IBES 
projections are updated on an irregular basis as analysts revise their 
forecasts.
    57. Consistent with our policy for public utilities, we consider 
using Value Line growth estimates in our revised natural gas and oil 
pipeline ROE methodology in the CAPM while continuing our longstanding 
use of IBES three to five-year growth estimates as the source of the 
short-term growth projection in the DCF. As discussed in Opinion No. 
569-A, because we are newly adopting the CAPM, we find that it is 
appropriate to consider using a new data source within the CAPM.
6. Proxy Group Construction
a. Background
    58. As discussed above, the companies included in a proxy group 
must be comparable in risk to the pipeline whose rate is being 
determined. To ensure that companies included in pipeline proxy groups 
are risk-appropriate, the Commission has required that each proxy group 
company satisfy three criteria: (1) The company's stock must be 
publicly traded; (2) the company must be recognized as a natural gas or 
oil pipeline company and its stock must be recognized and tracked by an 
investment information service such as Value Line; and (3) pipeline 
operations must constitute a high proportion of the company's 
business.\124\ In determining whether a company's pipeline operations 
constitute a high proportion of its business, the Commission has 
historically applied a 50% standard requiring that the pipeline 
business account for, on average, at least 50% of the company's assets 
or operating income over the most recent three-year period.\125\ 
Furthermore, in addition to the foregoing criteria, the Commission has 
declined to include Canadian companies in pipeline proxy groups.\126\
---------------------------------------------------------------------------

    \124\ 2008 Policy Statement, 123 FERC ] 61,048 at P 8.
    \125\ Opinion No. 486-B, 126 FERC ] 61,034 at PP 8, 59.
    \126\ For example, in Opinion No. 486-B, the Commission excluded 
TransCanada Corporation from the proxy group in a natural gas 
pipeline proceeding based in part on the fact that its Canadian 
pipeline ``was subject to a significantly different regulatory 
structure that renders it less comparable to domestic pipelines 
regulated by the Commission.'' Id. P 60. The Commission again 
affirmed the exclusion of TransCanada Corporation in Opinion No. 
528, finding that it was ``subject to the vagaries of Canadian 
regulation and Canadian capital markets, thereby making it difficult 
to establish comparable risk.'' Opinion No. 528, 145 FERC ] 61,040 
at P 626.
---------------------------------------------------------------------------

    59. The Commission has explained that proxy groups ``should consist 
of at least four, and preferably at least five members'' \127\ and that 
pipeline proxy groups should only exceed five members if each 
additional member satisfies the 50% standard.\128\ At the same time, 
the Commission has also explained that although ``adding more members 
to the proxy group results in greater statistical accuracy, this is 
true

[[Page 31768]]

only if the additional members are appropriately included in the proxy 
group as representative firms.'' \129\
---------------------------------------------------------------------------

    \127\ Opinion No. 486-B, 126 FERC ] 61,034 at P 104.
    \128\ See Portland Nat. Gas Transmission Sys., Opinion No. 510, 
134 FERC ] 61,129, at P 215 (2011) (declining to include company 
that failed 50% standard because proxy group had more than five 
members).
    \129\ Opinion No. 486-B, 126 FERC ] 61,034 at P 104.
---------------------------------------------------------------------------

    60. The number of companies satisfying the Commission's historical 
proxy group criteria in pipeline proceedings has declined in recent 
years, resulting in inadequately sized proxy groups. Consolidation in 
the natural gas and oil pipeline industries has resulted in the 
absorption of many natural gas and oil pipeline companies into larger, 
diversified energy companies that own a variety of energy-related 
assets in addition to interstate pipelines. In addition, major 
companies in the oil pipeline industry have recently acquired natural 
gas pipeline assets.\130\ The proliferation of these diversified energy 
companies has reduced the number of companies satisfying the 50% 
standard. Recent acquisitions of pipeline companies by private equity 
firms have further reduced the number of eligible natural gas and oil 
pipeline proxy group members by converting those pipeline companies 
from publicly traded to privately held entities.
---------------------------------------------------------------------------

    \130\ Examples of such transactions include Enbridge Inc.'s 
acquisition of Spectra Energy Corp., TC Energy Corporation's 
acquisition of Columbia Pipeline Group, Inc., and IFM Investors' 
acquisition of Buckeye Partners LP.
---------------------------------------------------------------------------

    61. To address the problem of the shrinking natural gas and oil 
pipeline proxy groups, the Commission has relaxed the 50% standard when 
necessary to construct a proxy group of five members.\131\ The 
Commission has emphasized, however, that it will only include firms not 
satisfying the 50% standard until five proxy group members are 
obtained.\132\
---------------------------------------------------------------------------

    \131\ E.g., Opinion No. 528, 145 FERC ] 61,040 at P 635; Opinion 
No. 486-B, 126 FERC ] 61,034 at PP 67-75, 94-96 (including two firms 
not satisfying the 50% standard in natural gas pipeline proxy group 
after application of the Commission's traditional criteria resulted 
in a proxy group of only three members); Williston Basin Interstate 
Pipeline Co., 104 FERC ] 61,036, at PP 35-37, 43 (2003), order on 
reh'g and compliance, 107 FERC ] 61,164 (2004).
    \132\ Opinion No. 528-A, 154 FERC ] 61,120 at P 236 (``[W]e will 
relax the [50 percent] standard only if necessary to establish a 
proxy group consisting of at least five members''); Opinion No. 510, 
134 FERC ] 61,129 at P 167 (``[I]n order to achieve a proxy group of 
at least five firms, a diversified natural gas company not 
satisfying the historical [50 percent] standard could be included in 
the proxy group, but only if there is a convincing showing that an 
investor would view that firm as having comparable risk to a 
pipeline.'').
---------------------------------------------------------------------------

b. NOI Comments
    62. Commenters recognize the ongoing difficulties in forming 
pipeline proxy groups of sufficient size and support the Commission's 
policy of relaxing the 50% standard when necessary to obtain five proxy 
group members.\133\ AOPL, INGAA, and Tallgrass assert that the 
Commission should not apply the 50% standard as a rigid screen and 
continue to allow the inclusion of companies that do not satisfy the 
50% standard but are nonetheless significantly involved in 
jurisdictional natural gas and oil pipeline operations.\134\ NGSA and 
PGC/AF&PA likewise support continued flexibility in the construction of 
pipeline proxy groups.\135\
---------------------------------------------------------------------------

    \133\ E.g., CAPP Initial Comments at 19; AOPL Initial Comments 
at 35; NGSA Initial Comments at 11.
    \134\ See AOPL Initial Comments at 15, 17-18, 35; INGAA Initial 
Comments at 24, 29-30; Tallgrass Initial Comments at 9.
    \135\ NGSA Initial Comments at 11, 17; PGC/AF&PA Joint Comments 
at 9-10.
---------------------------------------------------------------------------

    63. Other commenters urge the Commission to adopt more drastic 
changes to its proxy group formation policies. For example, Magellan 
states that the Commission should allow the inclusion of risk-
appropriate non-energy companies in natural gas and oil pipeline proxy 
groups \136\ while APGA recommends permitting the inclusion of natural 
gas distributors.\137\ INGAA proposes several additional changes to the 
Commission's natural gas pipeline proxy group policy,\138\ including 
allowing for the inclusion of risk-comparable Canadian companies with 
significant U.S. interstate natural gas pipeline assets in natural gas 
pipeline proxy groups.\139\ NGSA also supports this proposal.\140\ 
Moreover, INGAA and Tallgrass propose using the financial metric 
``beta'' to assist in determining whether potential proxy group members 
are comparable in risk to the pipeline at issue.\141\
---------------------------------------------------------------------------

    \136\ Magellan Initial Comments at 15; see also NextEra 
Transmission, LLC Initial Comments at 5-6. Most commenters oppose 
including non-energy companies in pipeline proxy groups. E.g., AOPL 
Initial Comments at 32; Tallgrass Initial Comments at 9; CAPP 
Initial Comments at 21; NGSA Initial Comments at 19; PGC/AF&PA Joint 
Comments at 10.
    \137\ APGA Comments at 10.
    \138\ INGAA Initial Comments at 24-25, 29-37, 40; INGAA Reply 
Comments at 6-12.
    \139\ INGAA Initial Comments at 30.
    \140\ NGSA Initial Comments at 11.
    \141\ INGAA Initial Comments at 24-25, 34-35; Tallgrass Initial 
Comments at 6-7.
---------------------------------------------------------------------------

c. Commission Determination
    64. Based on our review of our current policy and upon 
consideration of the comments to the NOI, we will maintain a flexible 
approach to forming natural gas and oil pipeline proxy groups and 
continue to relax the 50% standard when necessary to obtain a proxy 
group of five members. In addition, we clarify that in light of 
continuing difficulties in forming sufficiently sized natural gas and 
oil pipeline proxy groups, we will consider proposals to include 
otherwise-eligible Canadian entities.\142\ We recognize that 
difficulties in forming a proxy group of sufficient size may be 
enhanced under current market conditions, including those resulting 
from the COVID-19 pandemic. In light of these conditions, the 
Commission will consider adjustments to our ROE policies where 
necessary.\143\
---------------------------------------------------------------------------

    \142\ While the Commission has preferred screens and methods for 
selecting companies that will compose a proxy group, parties may 
continue to propose alternative screens and methods in cost-of-
service rate proceedings.
    \143\ See, e.g., SFPP, L.P., Opinion No. 511, 134 FERC ] 61,121, 
at P 209 (2011) (departing from the Commission's general policy to 
determine ROE using the most recent data in the record and 
determining nominal ROE using earlier data where the most recent 
data reflected the collapse of the stock market in late 2008 and 
thus was not representative of the pipeline's long-term equity cost 
of capital), order on reh'g, Opinion No. 511-B, 150 FERC ] 61,096 
(2015) remanded on other grounds sub nom. United Airlines, Inc. v. 
FERC, 827 F.3d 122 (D.C. Cir. 2016), order on remand and compliance 
filing, Opinion No. 511-C, 162 FERC ] 61,228, at PP 46-53 (2018); 
see also Trunkline Gas Co., Opinion No. 441, 90 FERC ] 61,017, at 
61,049 (2000) (``The Commission seeks to find the most 
representative figures on which to base rates.'').
---------------------------------------------------------------------------

    65. As discussed above, the problem of the shrinking pipeline proxy 
groups persists due to, among other issues, the consolidation of pure 
play natural gas and oil pipelines into diversified energy companies 
and acquisitions of pipeline companies by private firms. These 
developments have reduced the number of publicly traded companies 
eligible for inclusion in a proxy group under the Commission's 
historical criteria, making it difficult for the Commission to develop 
an adequate sample of representative firms to estimate a pipeline's 
required cost of equity. As such, we will continue to apply the 50% 
standard flexibly, based on the record evidence and in accordance with 
the Commission's past practice, when necessary to construct a proxy 
group of at least five members.
    66. In addition, we find that the NOI comments advance credible 
reasons why it may be appropriate to permit the inclusion of Canadian 
entities in natural gas and oil pipeline proxy groups. Extending proxy 
group eligibility to such entities could alleviate the shrinking proxy 
group problem by adding new potential proxy group members. As explained 
above, the Commission has previously excluded companies from pipeline 
proxy groups based on concerns that the fact that such entities are 
subject to Canadian regulation and Canadian capital markets makes it 
difficult to establish whether

[[Page 31769]]

they are comparable in risk to Commission-regulated pipelines.\144\ We 
note, however, that considerations underlying those decisions may have 
changed since the Commission established that policy.\145\ Therefore, 
in future natural gas and oil pipeline proceedings, we will consider 
proposals to include in the proxy group risk-appropriate Canadian 
entities that otherwise satisfy the Commission's proxy group 
eligibility requirements.
---------------------------------------------------------------------------

    \144\ Opinion No. 528, 145 FERC ] 61,040 at P 626; Opinion No. 
486-B, 126 FERC ] 61,034 at P 60.
    \145\ For instance, a 2009 rate case decision by the National 
Energy Board of Canada (NEB) may be instructive. National Energy 
Board of Canada, RH-1-2008 Reasons for Decision, Trans Qu[eacute]bec 
& Maritimes Pipelines Inc., March 2009, available at http://www.regie-energie.qc.ca/audiences/3690-09/RepDDRGM_3690-09/B-29_GM_Reasons-Decision-RH-1-2008_3690_30juin09.pdf (Trans 
Qu[eacute]bec). In that decision, the NEB revised its ratemaking 
policy by adopting an after-tax weighted average cost-of-capital 
approach to determining pipeline cost of capital. Id. at 18-19. The 
NEB also accepted evidence that the Canadian and U.S. financial 
markets are integrated and, as a result, Canadian pipelines and U.S. 
pipelines compete for capital. Id. at 66-68 (finding that ``Canadian 
and U.S. pipelines operate in what the Board views as an integrated 
North American natural gas market.''). The NEB also found that 
although the risks facing U.S. and Canadian pipelines are not 
identical, those risks ``are not so different as to make them 
inappropriate comparators'' and in fact share ``many similarities.'' 
Id. at 68. As such, the NEB found that U.S. pipelines ``have the 
potential to act as a useful proxy'' for use in determining the 
appropriate ROE for Canadian pipelines. Id. at 67.
---------------------------------------------------------------------------

B. Excluded Financial Models

1. Risk Premium
a. Background
    67. In Opinion No. 569, the Commission excluded the Risk Premium 
model from its revised ROE methodology for public utilities.\146\ The 
Commission found that the Risk Premium model is largely redundant with 
the CAPM because, although they rely on different data sources to 
determine the risk premium, both models use indirect measures (i.e., 
past Commission orders in the Risk Premium model and S&P 500 data in 
the CAPM) to ascertain the risk premium that investors require over the 
risk-free rate of return.\147\ The Commission also found that the Risk 
Premium model is likely to provide a less accurate current cost-of-
equity estimate than the DCF model or CAPM because whereas those models 
apply a market-based method to primary data, the Risk Premium model 
relies on previous ROE determinations whose resulting ROE may not 
necessarily be directly determined by a market-based method.\148\
---------------------------------------------------------------------------

    \146\ Opinion No. 569, 169 FERC ] 61,129 at P 340.
    \147\ Id. P 341.
    \148\ Id. P 342.
---------------------------------------------------------------------------

    68. In Opinion No. 569-A, the Commission granted rehearing and 
adopted a modified Risk Premium model for use in ROE analyses under FPA 
section 206. Unlike the Risk Premium model discussed in Opinion No. 
569, the modified Risk Premium model excludes problematic cases from 
the analysis, such as those where an entity joined a Regional 
Transmission Organization (RTO), and the Commission, without 
reexamination, allowed adoption of the existing RTO-wide ROE. The 
Commission explained that, as modified, the Risk Premium model adds 
benefits to the ROE analysis through model diversity and reduced 
volatility that outweigh the disadvantages identified in Opinion No. 
569.\149\
---------------------------------------------------------------------------

    \149\ Opinion No. 569-A, 171 FERC ] 61,154 at PP 104-114.
---------------------------------------------------------------------------

b. NOI Comments
    69. INGAA, AOPL, NGSA, and CAPP assert that the Risk Premium model 
cannot be applied to natural gas and oil pipelines in light of the lack 
of stated allowed ROEs from settlements or Commission decisions in 
pipeline proceedings. Because the Risk Premium model relies upon 
Commission-allowed ROEs to estimate the equity risk premium, these 
commenters state that it would be difficult, if not impossible, to 
apply this model in pipeline cases.\150\
---------------------------------------------------------------------------

    \150\ INGAA Initial Comments at 41-42; AOPL Initial Comments at 
12, 27-28; NGSA Initial Comments at 10-11, 24; CAPP Initial Comments 
at 11-12.
---------------------------------------------------------------------------

c. Commission Determination
    70. We will not use the Risk Premium model in our revised ROE 
methodology. As commenters observe, there is insufficient data to apply 
the Risk Premium models considered in Opinion Nos. 569 and 569-A to 
natural gas or oil pipelines. That model relies upon stated ROEs 
approved in past Commission orders, such as orders on settlements, to 
ascertain the risk premium that investors require. In recent years, 
however, natural gas and oil pipeline cost-of-service rate proceedings 
have frequently resulted in ``black box'' settlements instead of a 
fully litigated Commission decision. Unlike public utility proceedings, 
where ROE may be addressed on a standalone basis as a component of 
formula rates, settlements in pipeline proceedings typically do not 
enumerate a stated ROE.
    71. Consequently, for natural gas and oil pipelines, there is 
insufficient data to estimate cost of equity using the Risk Premium 
models discussed in Opinion Nos. 569 and 569-A. In light of this lack 
of data, we will not use these models in determining pipeline ROEs. 
While we do not adopt the Risk Premium model in our revised methodology 
here for the reasons discussed above, we do not necessarily foreclose 
its use in future proceedings if parties can demonstrate that the 
concerns discussed above have been addressed.
2. Expected Earnings
a. Background
    72. In Opinion No. 569, the Commission excluded the Expected 
Earnings model from its revised base ROE methodology for public 
utilities because the record did not support departing from the 
Commission's traditional use of market-based approaches to determine 
base ROE.\151\ The Commission also found that the record did not 
demonstrate that investors rely on Expected Earnings when making 
investment decisions.\152\
---------------------------------------------------------------------------

    \151\ Opinion No. 569, 169 FERC ] 61,129 at PP 200-201.
    \152\ Id. PP 212-218.
---------------------------------------------------------------------------

    73. The Commission explained that in determining a just and 
reasonable ROE under Hope, it must analyze the returns that are earned 
on ``investments in other enterprises having corresponding risks.'' 
\153\ In contrast to market-based models, the accounting-based Expected 
Earnings model uses estimates of return on an entity's book value to 
estimate the earnings an investor expects to receive on the book value 
of a particular stock.\154\ As investors cannot invest in an enterprise 
at book value, the Commission concluded that the expected return on a 
utility's book value does not reflect ``returns on investments in other 
enterprises'' because in most circumstances book value does not reflect 
the value of any investment that is available to an investor in the 
market.\155\ The Commission thus found that return on book value is not 
indicative of what return an investor requires to invest in the 
utility's equity or what return an investor receives on the equity 
investment.\156\
---------------------------------------------------------------------------

    \153\ Id. P 201 (quoting Hope, 320 U.S. at 603).
    \154\ Id. P 172.
    \155\ Id. P 201.
    \156\ Id. PP 202, 211.
---------------------------------------------------------------------------

    74. On rehearing, the Commission affirmed the exclusion of the 
Expected Earnings model in those proceedings for the reasons stated in 
Opinion No. 569.\157\ The Commission found, moreover, that the Expected 
Earnings model does not accurately measure the returns that investors 
require to invest in public utilities because the current market values 
of utility stocks

[[Page 31770]]

substantially exceed utilities' book value. As a result, a utility's 
expected earnings on its book value will inevitably exceed the return 
that investors require in order to purchase the utility's higher-value 
stock.\158\
---------------------------------------------------------------------------

    \157\ Opinion No. 569-A, 171 FERC ] 61,154 at PP 125-131.
    \158\ Id. P 127.
---------------------------------------------------------------------------

b. NOI Comments
    75. Commenters that support expanding the Commission's pipeline ROE 
methodology to consider models in addition to the DCF \159\ do not 
oppose using the Expected Earnings model. INGAA supports use of the 
Expected Earnings model to determine natural gas pipeline ROEs,\160\ 
and AOPL states that the Expected Earnings model can be applied to oil 
pipelines if the Commission adopts an appropriate approach to 
outliers.\161\ Among the commenters that oppose applying the Expected 
Earnings model to natural gas and oil pipelines, NGSA criticizes the 
Expected Earnings model for ignoring capital markets \162\ while CAPP 
asserts that the Expected Earnings model appears to be confined to 
academic uses and, in any event, there is likely an insufficient number 
of pipelines to implement the Expected Earnings model.\163\
---------------------------------------------------------------------------

    \159\ As noted above, several commenters, including Airlines for 
America, Liquids Shippers Group, NGSA, APGA, and PGC/AF&PA assert 
that the Commission should continue relying solely on the DCF model 
in analyzing pipeline ROEs.
    \160\ INGAA Initial Comments at 8, 41, 63; INGAA Reply Comments 
at 1-2.
    \161\ AOPL Initial Comments at 28l; see also Plains Initial 
Comments at 4; Magellan Initial Comments at 12-13, 28-29 (stating 
that Expected Earnings should be used only in conjunction with other 
models such as the DCF, CAPM, and Risk Premium).
    \162\ NGSA Initial Comments at 34.
    \163\ CAPP Initial Comments at 13, 27.
---------------------------------------------------------------------------

c. Commission Determination
    76. We will not use the Expected Earnings model to determine ROE 
for natural gas and oil pipelines for the reasons stated in Opinion No. 
569. We conclude that the findings underlying the Commission's decision 
to exclude the Expected Earnings model from our analysis of public 
utility ROEs also support excluding that model from our analysis of 
natural gas and oil pipeline ROEs.
    77. As discussed above, the Commission must ensure that the 
``return to the equity owner'' is ``commensurate with returns on 
investments in other enterprises having corresponding risks.'' \164\ As 
with public utilities, under the market-based approach the Commission 
performs this analysis by setting a pipeline's ROE to equal the 
estimated return that investors would require in order to purchase 
stock in the pipeline at its current market price. However, the return 
on book value measured under the Expected Earnings model does not 
permit such an analysis. Like investors in utilities, investors in 
natural gas and oil pipelines cannot invest at the pipeline's book 
value and must instead pay the prevailing market price. As such, the 
expected return on the pipeline's book value does not reflect the value 
of an investment that is available to an investor in the market and 
thus does not reflect the ``returns on investments in other enterprises 
having corresponding risks'' that we must analyze under Hope.\165\ 
Likewise, the return on a pipeline's book value does not reflect ``the 
return to the equity owner'' that we must consider under Hope because 
the return that an investor requires to invest in the pipeline's equity 
and the return an investor receives on the equity investment are 
determined based on the current market price the investor must pay in 
order to invest in the pipeline's equity.\166\
---------------------------------------------------------------------------

    \164\ Hope, 320 U.S. at 603.
    \165\ See Opinion No. 569, 169 FERC ] 61,129 at P 201.
    \166\ See id. P 202.
---------------------------------------------------------------------------

    78. Accordingly, based on the record in this proceeding, we 
conclude that at this time relying on the Expected Earnings model to 
determine pipeline ROEs would not satisfy the requirements of Hope. We 
will therefore exclude the Expected Earnings model from our revised 
methodology for determining natural gas and oil pipeline ROEs. While we 
do not adopt the Expected Earnings model in our revised methodology 
here for the reasons discussed above, we do not necessarily foreclose 
its use in future proceedings if parties can demonstrate that the 
concerns discussed above have been addressed.

C. Outlier Tests

1. Background
    79. Generally, the Commission has not applied a specific low-end or 
high-end outlier test in natural gas and oil pipeline proceedings. 
Rather, the Commission has used a fact-specific analysis to select 
proxy group members. In constructing pipeline proxy groups, the 
Commission excludes anomalous and illogical proxy group returns that do 
not provide meaningful indicia of the return a pipeline requires to 
attract capital.\167\
---------------------------------------------------------------------------

    \167\ See Opinion No. 546, 154 FERC ] 61,070 at P 196; 2008 
Policy Statement, 123 FERC ] 61,048 at P 79 (``[T]he Commission will 
continue to exclude an MLP from the proxy groups if its growth 
projection is illogical or anomalous.'').
---------------------------------------------------------------------------

    80. Conversely, the Commission has applied specific outlier screens 
to public utilities. Prior to Opinion No. 569, the Commission excluded 
as low-end outliers companies whose ROEs failed to exceed the average 
10-year bond-yield by approximately 100 basis points on the ground that 
investors generally cannot be expected to purchase a common stock if 
debt, which has less risk than a common stock, yields essentially the 
same expected return.\168\ In the Briefing Orders, the Commission 
proposed to treat as high-end outliers any proxy company whose cost of 
equity estimated under the model in question is more than 150% of the 
median result of all of the potential proxy group members in that model 
before any high-end or low-end outlier test is applied.\169\
---------------------------------------------------------------------------

    \168\ Opinion No. 569, 169 FERC ] 61,129 at P 379 (citing 
Pioneer Transmission, LLC, 126 FERC ] 61,281, at P 94 (2009), reh'g 
denied, 130 FERC ] 61,044 (2010); S. Cal. Edison Co., 131 FERC ] 
61,020, at PP 54-56 (2010)).
    \169\ MISO Briefing Order, 165 FERC ] 61,118 at P 54; Coakley 
Briefing Order, 165 FERC ] 61,030 at P 53.
---------------------------------------------------------------------------

    81. In Opinion No. 569, the Commission adopted a revised low-end 
outlier test that eliminates proxy group ROE results that are less than 
the yields of generic corporate Baa bond plus 20% of the CAPM risk 
premium.\170\ The Commission explained that it was necessary to include 
a risk premium in the low-end outlier test to account for the fact that 
declining bond yields have caused the ROE that investors would consider 
to yield ``essentially the same expected return as a bond'' to 
increase.\171\ The Commission concluded that the 20% risk premium was 
reasonable because it is sufficiently large to account for the 
additional risks of equities over bonds, but not so large as to 
inappropriately exclude proxy group members whose ROE is 
distinguishable from debt.\172\
---------------------------------------------------------------------------

    \170\ Opinion No. 569, 169 FERC ] 61,129 at P 387.
    \171\ Id.
    \172\ Id. P 388.
---------------------------------------------------------------------------

    82. In addition, Opinion No. 569 adopted the high-end outlier test 
proposed in the Briefing Orders.\173\ The Commission reasoned that 
because the Commission will continue to use the midpoint as the measure 
of central tendency for region-wide public utility ROEs, a high-end 
outlier test was necessary to eliminate proxy group members whose ROEs 
are unreasonably high.\174\
---------------------------------------------------------------------------

    \173\ Id. P 375.
    \174\ Id.
---------------------------------------------------------------------------

    83. The Commission explained that both the low-end and high-end 
outlier tests would be subject to a natural-break analysis, which 
determines whether

[[Page 31771]]

proxy group companies screened as outliers, or those almost screened as 
outliers, truly reflect non-representative data and should thus be 
removed from the proxy group.\175\ The Commission noted that the 
natural break analysis provides the Commission with flexibility to 
reach a reasonable result based on the particular array of ROEs 
presented in a particular case.\176\
---------------------------------------------------------------------------

    \175\ Id. P 396. Typically, this involves examining the distance 
between that proxy group company and the next closest proxy group 
company and comparing that to the dispersion of other proxy group 
companies. As explained in Opinion No. 569, the natural break 
analysis may justify excluding companies whose ROEs are a few basis 
points above the low-end outlier screen if their ROEs are far lower 
than other companies in the proxy group, and a similar analysis 
could apply with regard to high-end outliers. Id.
    \176\ Id. P 397.
---------------------------------------------------------------------------

    84. In Opinion No. 569-A, the Commission denied requests for 
rehearing as to the low-end outlier test. The Commission rejected 
challenges to the threshold based on 20% of the CAPM risk premium and 
similarly rejected claims that the low-end outlier test is inconsistent 
with Commission precedent.\177\
---------------------------------------------------------------------------

    \177\ Opinion No. 569-A, 171 FERC ] 61,154 at P 161.
---------------------------------------------------------------------------

    85. Moreover, the Commission modified the high-end outlier test 
adopted in Opinion No. 569 to increase the exclusion threshold to 200% 
of the median result of all the potential proxy group members in the 
model in question before any high or low-end outlier test is applied. 
The Commission recognized that a high-end outlier test with a bright-
line threshold could inappropriately exclude rational ROEs that are not 
anomalous for the subject utility and found that increasing the 
threshold to 200% will reduce the risk that such rational results are 
inappropriately excluded.\178\
---------------------------------------------------------------------------

    \178\ Id. P 154.
---------------------------------------------------------------------------

2. NOI Comments
    86. Most commenters agree that the outlier tests proposed in the 
Briefing Orders are not appropriate for natural gas or oil 
pipelines.\179\ These commenters assert that outlier tests are 
unnecessary because the Commission sets natural gas and oil pipeline 
ROEs at the median of the proxy group results, which reduces the 
distortion that high-end cost of equity estimates may cause when the 
ROE is set at the midpoint of the proxy group results.\180\ CAPP, by 
contrast, states that the outlier tests proposed in the Briefing Orders 
would be useful in forming proxy groups.\181\ Similarly, although it 
opposes use of a high-end outlier test, INGAA states that there is 
theoretical support for applying a low-end outlier test.\182\ However, 
INGAA opposes the proposed low-end outlier test's 20% threshold and 
proposes two alternative approaches.\183\
---------------------------------------------------------------------------

    \179\ AOPL Initial Comments at 4, 15-17; INGAA Initial Comments 
at 10-11, 65-69; Plains Comments at 1-2, 5-6.
    \180\ AOPL Initial Comments at 16; INGAA Initial Comments at 67; 
Plains Comments at 5-6; NGSA Comments at 20. Magellan states that it 
may be unreasonable to apply an outlier test to oil pipelines 
because removing outlying results could reduce the number of proxy 
group companies to an unacceptable level. Magellan Initial Comments 
at 17-18.
    \181\ CAPP Initial Comments at 21-22.
    \182\ INGAA Initial Comments at 69.
    \183\ Id.
---------------------------------------------------------------------------

3. Commission Determination
    87. We decline to adopt specific outlier tests for use in 
determining natural gas and oil pipeline ROEs. Rather, we will continue 
to address outliers in pipeline proxy groups on a case-by-case basis in 
accordance with our policy to remove ``anomalous'' or ``illogical'' 
cost-of-equity estimates that do not provide meaningful indicia of the 
returns that a pipeline needs to attract capital from the market.\184\
---------------------------------------------------------------------------

    \184\ E.g., Opinion No. 546, 154 FERC ] 61,070 at P 196.
---------------------------------------------------------------------------

    88. We believe that rigid outlier screens are unnecessary for 
natural gas and oil pipelines for two reasons. First, as commenters 
observe, the Commission's use of the proxy group median in setting 
pipeline ROEs reduces the effect that low and high-end outliers may 
exert on the ROE result. When the Commission sets an ROE at the 
midpoint, as it does for RTO-wide ROEs in the public utility context, 
the ROE is set at the average of the highest and lowest ROEs of the 
proxy group members.\185\ The low and high-end returns are therefore 
direct inputs into the calculation of the midpoint the Commission uses 
to determine the ROE. In contrast, when the Commission uses the median 
to determine the ROE of a pipeline, the presence of an outlier has a 
much smaller effect.\186\
---------------------------------------------------------------------------

    \185\ E.g., Midwest Indep. Transmission Sys. Operator, Inc., 106 
FERC ] 61,302, at PP 8-10 (2004).
    \186\ Although the decision whether to include or remove an 
outlier may affect which member of the proxy group is the median 
result, the outlier is not a direct part of the ROE calculation as 
it is when the Commission uses the midpoint.
---------------------------------------------------------------------------

    89. Second, as discussed above, the pool of entities eligible for 
inclusion in natural gas and oil pipeline proxy groups has declined in 
recent years and remains small. Adopting rigid outlier screens could 
further reduce the number of potential proxy group members and make it 
difficult to form pipeline proxy groups with at least four or five 
members.
    90. We also clarify that we do not anticipate applying a natural 
break analysis in pipeline ROE proceedings. Unlike in the public 
utility context, we are concerned that a natural break analysis could 
exacerbate the difficulties in forming pipeline proxy groups by further 
reducing the number of potential proxy group members. Moreover, we 
believe that the natural break analysis is less useful in pipeline 
proceedings. As explained in Opinion No. 569, the purpose of the 
natural break analysis is to provide the Commission with flexibility to 
determine whether a proxy group company ROE is truly an outlier or 
contains useful information.\187\ Because there are so few members of 
pipeline proxy groups, the natural break analysis is less likely to 
identify outliers as this typically involves examining the distance 
between a given proxy group result and the next closest result, and 
comparing that to the dispersion of other proxy group results.\188\
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    \187\ Opinion No. 569, 169 FERC ] 61,129 at P 395.
    \188\ Id. P 390.
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    91. We will continue to apply the general principle that 
``anomalous'' or ``illogical'' data should be excluded from the proxy 
group. Using this approach, the Commission will retain flexibility to 
determine whether a given proxy group company is truly an outlier or 
whether it contains useful information in light of the particular array 
of ROEs presented by the potential proxy group companies.\189\
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    \189\ Id. P 395.
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D. Oil Pipeline Page 700s

    92. In light of the impending five-year review of the oil pipeline 
index, we encourage oil pipelines to file updated FERC Form No. 6, page 
700 data for 2019 reflecting the revised ROE methodology established 
herein. Although the Commission will address this issue further in the 
five-year review, reflecting the revised methodology in page 700 data 
for 2019 may help the Commission better estimate industry-wide cost 
changes for purposes of the five-year review. Pipelines that previously 
filed Form No. 6 for 2019 and choose to submit updated page 700 data 
should, in a footnote on the updated page 700, either (a) confirm that 
their previously filed Form No. 6 was based solely upon the DCF model 
or (b) provide the real ROE and resulting cost of service based solely 
upon the DCF model as it was applied to oil pipelines prior to this 
Policy Statement.

[[Page 31772]]

    93. As discussed below, the Paperwork Reduction Act (PRA) \190\ 
requires each federal agency to seek and obtain the Office of 
Management and Budget's (OMB) approval before undertaking a collection 
of information directed to ten or more persons. Following OMB approval 
of this voluntary information collection, the Commission will issue a 
notice affording pipelines two weeks to file updated page 700 data 
reflecting the revised ROE methodology.\191\ Before that time, 
pipelines that have not filed Form No. 6 for 2019 (e.g., pipelines that 
have received an extension of the Form No. 6 filing deadline) should 
file page 700 data consistent with their previously-granted extensions 
and such filings should be based upon the DCF model, which was the 
Commission's oil pipeline ROE methodology as of April 20, 2020, the 
date such filings were due.\192\
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    \190\ 44 U.S.C. 3501-21.
    \191\ Following OMB approval of this information collection, the 
Commission will issue a notice specifying the date on which any 
updated page 700 should be filed.
    \192\ Upon OMB approval, these pipelines will have the 
opportunity to file updated page 700 data reflecting the 
Commission's revised oil pipeline ROE methodology.
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III. Information Collection Statement

    94. The PRA requires each federal agency to seek and obtain OMB 
approval before undertaking a collection of information directed to ten 
or more persons.\193\ Upon approval of a collection of information, OMB 
will assign an OMB Control Number and expiration date. The refiling of 
page 700 of FERC Form No. 6 is being requested on a voluntary basis.
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    \193\ OMB's regulations requiring approval of certain 
collections of information are at 5 CFR 1320.
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    95. The Commission is submitting this voluntary information 
collection (the one-time re-filing of page 700 of FERC Form No. 6) to 
OMB for its review and approval under section 3507(d) of the PRA. The 
Commission solicits comments on the Commission's need for this 
information, whether the information will have practical utility, the 
accuracy of the burden estimates, ways to enhance the quality, utility, 
and clarity of the information to be collected or retained, and any 
suggested methods for minimizing respondents' burden, including the use 
of automated information techniques.
    96. Burden Estimate: \194\ The estimated additional one-time burden 
and cost \195\ for making a voluntary filing to update page 700 of the 
FERC Form No. 6 consistent with this Policy Statement is detailed in 
the following table. The first row includes the industry cost of 
performing cost-of-equity studies to develop an updated ROE estimate 
for the period ending December 31, 2019. The second row shows the cost 
of reflecting the updated ROE estimates and revised Annual Cost of 
Service on page 700 of the FERC Form No. 6.
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    \194\ ``Burden'' is the total time, effort, or financial 
resources expended by persons to generate, maintain, retain, or 
disclose or provide information to or for a Federal agency. For 
further explanation of what is included in the information 
collection burden, refer to 5 CFR 1320.3.
    \195\ Commission staff estimates that the industry's skill set 
and cost (for wages and benefits) for completing and filing FERC 
Form No. 6 is comparable to the Commission's skill set and average 
cost. The FERC 2019 average salary plus benefits for one FERC full-
time equivalent (FTE) is $167,091/year or $80.00/hour.

                                            Estimated Annual Changes to Burden due to Docket No. PL19-4 \196\
                                                                [Figures may be rounded]
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                                          Number of     Annual number                                              Total annual  burden
                                          potential     of responses    Total number    Average burden hours &     hours & total annual      Cost per
                                         respondents   per respondent   of responses     cost ($) per response           cost ($)         respondent ($)
                                                  (1)             (2)     (1) * (2) =  (4).....................  (3) * (4) = (5)........     (5) / (1) =
                                                                                  (3)                                                                (6)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Updated ROE Study....................             244               1             244  187.5 hrs.; $15,000.....  45,750 hrs.; $3,660,000         $15,000
Refile FERC Form No. 6, page 700.....             244               1             244  0.5 hrs.; $40...........  122 hrs.; $9,760.......              40
                                      ------------------------------------------------------------------------------------------------------------------
    Total Changes, Due to PL19-4.....             244               1             244  ........................  $3,669,760.............          15,040
--------------------------------------------------------------------------------------------------------------------------------------------------------

    97. This additional one-time burden is expected to be imposed in 
Year 1.
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    \196\ We have conservatively assumed a 100% voluntary response 
rate.
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    98. Title: FERC Form No. 6, Annual Report of Oil Pipeline 
Companies.
    Action: Revision to FERC Form No. 6, page 700.
    OMB Control No.: 1902-0022.
    Respondents: Oil pipelines.
    Frequency of Responses: One time.
    Necessity of the Information: As established in Order No. 561,\197\ 
oil pipelines may increase their existing transportation rates on an 
annual basis using an industry-wide index. The Commission reviews the 
index level every five years.\198\ In the five-year review, the 
Commission establishes the index level based upon a methodology that 
calculates pipeline cost changes on a per barrel-mile basis based upon 
FERC Form No. 6, page 700 data.\199\ Depending upon the record 
developed in the 2020 five-year review of the oil pipeline index, the 
Commission will consider using the updated FERC Form No. 6, page 700 
data for 2019 in that proceeding.
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    \197\ Revisions to Oil Pipeline Regulations Pursuant to the 
Energy Policy Act of 1992, Order No. 561, FERC Stats. & Regs. ] 
30,985 (1993), order on reh'g, Order No. 561-A, FERC Stats. & Regs. 
] 31,000 (1994), aff'd, Ass'n of Oil Pipelines v. FERC, 83 F.3d 1424 
(D.C. Cir. 1996).
    \198\ Id. at 30,941.
    \199\ Five-Year Review of the Oil Pipeline Index, 153 FERC ] 
61,312, at PP 5, 12 (2015).
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    99. Interested persons may obtain information on the reporting 
requirements by contacting the following: Federal Energy Regulatory 
Commission, 888 First Street NE, Washington, DC 20426 [Attention: Ellen 
Brown, Office of the Executive Director, email: [email protected] 
and phone: (202) 502-8663].
    100. Please send comments concerning the collection of information 
and the associated burden estimates to: Office of Information and 
Regulatory Affairs, Office of Management and Budget [Attention: Federal 
Energy Regulatory Commission Desk Officer]. Due to security concerns, 
comments should be sent directly to www.reginfo.gov/public/do/PRAMain. 
Comments submitted to OMB should be sent within 30 days of publication 
of this notice in the Federal Register and refer to FERC Form No. 6 and 
OMB Control No. 1902-0022.

[[Page 31773]]

IV. Document Availability

    101. 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 (http://www.ferc.gov)). At 
this time, the Commission has suspended access to the Commission's 
Public Reference Room, due to the proclamation declaring a National 
Emergency concerning the Novel Coronavirus Disease (COVID-19), issued 
by the President on March 13, 2020.
    102. 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 of this document in 
the docket number field.
    103. User assistance is available for eLibrary and the Commission's 
website during normal business hours from the Commission's Online 
Support at (202) 502-6652 (toll free at 1-866-208-3676) or email at 
[email protected], or the Public Reference Room at (202) 502-
8371, TTY (202) 502-8659. Email the Public Reference Room at 
[email protected].

V. Effective Date

    104. This Policy Statement becomes effective May 27, 2020.

    By the Commission.

    Issued: May 21, 2020.
Nathaniel J. Davis, Sr.,
Deputy Secretary.
[FR Doc. 2020-11406 Filed 5-26-20; 8:45 am]
BILLING CODE 6717-01-P