PL19-4, Policy Statement, published in Fed. Register

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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
Federal Energy Regulatory
Commission, DOE.
ACTION: Policy statement on determining
return on equity for natural gas and oil
pipelines.
AGENCY:

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.

SUMMARY:

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, Evan.Steiner@
ferc.gov
Monil Patel (Technical Information),
Office of Energy Market Regulation,
888 First Street NE, Washington, DC
20426, (202) 502–8296, Monil.Patel@
ferc.gov

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DATES:

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Seong-Kook Berry (Technical
Information), Office of Energy Market
Regulation, 888 First Street NE,
Washington, DC 20426, (202) 502–
6544, Seong-Kook.Berry@ferc.gov
SUPPLEMENTARY INFORMATION:
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
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
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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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
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:
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 shortterm 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 shortterm growth projection.8
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
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)).
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).
8 Seaway Crude Pipeline Co. LLC, Opinion No.
546, 154 FERC ¶ 61,070, at PP 198–200 (2016).

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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 longterm 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
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 ‘‘riskappropriate.’’ 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
9 2008

Policy Statement, 123 FERC ¶ 61,048 at P

6.

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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.
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 marketdetermined stock and dividend figures from public
companies comparable to a target company for
which those figures are unavailable. Marketdetermined 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,

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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
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:
R = rf + ba(rm¥rf)
rf = risk free rate (such as yield on 30year U.S. Treasury bonds)
rm = expected market return
ba = 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
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
85 FERC ¶ 61,323 (1998), aff’d, CAPP v. FERC, 254
F.3d 289).
17 NOI, 166 FERC ¶ 61,207 at PP 35, 38.
18 Opinion No. 569, 169 FERC ¶ 61,129 at P 229.
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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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:
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.
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:
R = E/B
E = Earnings during Current Year
B = Book Value at the End of the Prior
Year
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).
24 Opinion No. 569, 169 FERC ¶ 61,129 at P 305.
25 Id. P 172.
26 Opinion No. 569, 169 FERC ¶ 61,129 at P 172.

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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.
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
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
27 854

F.3d 9 (D.C. Cir. 2017).
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.
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.
35 Opinion No. 569, 169 FERC ¶ 61,129 at P 18.

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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.
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
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
36 Id.

PP 1, 18.
PP 276, 425.
38 Id. PP 18, 31, 200, 340.
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.
44 NOI, 166 FERC ¶ 61,207 at P 29.
45 Id. P 32.
37 Id.

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screening criteria and appropriate high
and low-end outlier tests.46
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
46 Id.

P 34.

47 Coakley

Briefing Order, 165 FERC ¶ 61,030 at
P 40; MISO Briefing Order, 165 FERC ¶ 61,118 at
P 42.

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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
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
b. NOI Comments

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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
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.
50 Opinion No. 569, 169 FERC ¶ 61,129 at PP 34,
171.
51 Id. PP 31, 34, 452.
52 Id. PP 39, 171.
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).

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that there is no reason to consider
additional models.55
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
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
26. In Hope, the Supreme Court held
that ‘‘the return to the equity owner
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.
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; SFPPCalnev Comments at 3–4; Tallgrass Initial
Comments at 1, 11.
58 E.g., AOPL Initial Comments at 4, 11; Tallgrass
Initial Comments at 2.
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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31763

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.
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
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).
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

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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
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.

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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 longterm growth of GDP, adjust the longterm growth projection of MLPs to equal
50% of GDP consistent with the 2008
Policy Statement,70 and use only 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).
69 Opinion No. 569, 169 FERC ¶ 61,129 at P 236.
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

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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.
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 longterm projection to one-fifth.73
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 onethird weighting to the long-term growth
projections in our analyses of pipeline
ROEs.
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
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.
71 AOPL Initial Comments at 41; NGSA Initial
Comments at 32–33; see also Magellan Initial
Comments at 23–24 (supporting two-thirds/onethird weighting should Commission retain existing
two-step DCF).
72 CAPP Initial Comments at 40.
73 INGAA Initial Comments at 55.
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).
75 Opinion No. 414–A, 84 FERC ¶ 61,084 (1998).

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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
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.
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 onethird 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.
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.
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.

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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 backwardlooking 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

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i. Background
37. In Opinion No. 569, the
Commission adopted the use of the 30year 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 longterm 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
79 Opinion No. 569, 169 FERC ¶ 61,129 at P 239
(citing Morin at 155–162).
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.

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adjustment in the CAPM analysis.85 The
Commission affirmed these conclusions
on rehearing.86
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
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 forwardlooking 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%.
40. First, as the Commission
recognized in Opinion No. 531–B, 30year U.S. Treasury bond yields are a
generally accepted proxy for the riskfree 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
85 Id.

PP 296–303.
No. 569–A, 171 FERC ¶ 61,154 at PP
75–77, 85.
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.
90 The appropriate data source for the short-term
growth projection in the DCF component of the
CAPM is addressed infra.
91 Opinion No. 531–B, 150 FERC ¶ 61,165 at P
114 (citing Morin at 151–152).
86 Opinion

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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.
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 wellrecognized 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.
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.
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
92 Opinion

No. 569, 169 FERC ¶ 61,129 at P 237.
P 260.
94 Id. PP 262–266.
95 See id. PP 260–276.
96 Id. P 268.
97 Id. P 297; Opinion No. 569–A, 171 FERC
¶ 61,154 at PP 75–76.
93 Id.

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observed that Dr. Morin supports the
use of adjusted betas in the CAPM.
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
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
iii. Commission Determination
46. We adopt the reasoning in
Opinion Nos. 569 and 569–A and find
98 Opinion

No. 569, 169 FERC ¶ 61,129 at PP 279,

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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.
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.

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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.
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
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 onethird weighting to the CAPM.113
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
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
110 CAPP

104 Opinion

No. 531–B, 150 FERC ¶ 61,165 at P

117.
105 Opinion

No. 569, 169 FERC ¶ 61,129 at P 296.
PP 296–297 (quoting Opinion No. 531–B,
150 FERC ¶ 61,165 at P 117).
107 Id. PP 425, 427.
108 Id. P 426.
109 Opinion No. 569–A, 171 FERC ¶ 61,154 at P
141.
106 Id.

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Initial Comments at 30.
OPC Initial Comments at 12.
112 INGAA Initial Comments at 8–9; Tallgrass
Initial Comments at 12.
113 NYPSC Initial Comments at 18.
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.
116 Opinion No. 569, 169 FERC ¶ 61,129 at P 120.
111 Maryland

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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
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.
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
117 Id.

P 276.
118 Id. P 125.
119 Id. P 128.
120 Opinion No. 569–A, 171 FERC ¶ 61,154 at PP
78–83.

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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
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
121 AOPL

Initial Comments at 38.
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.
122 INGAA

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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
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
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.
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).

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only if the additional members are
appropriately included in the proxy
group as representative firms.’’ 129
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 energyrelated 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.
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
b. NOI Comments
62. Commenters recognize the
ongoing difficulties in forming pipeline
proxy groups of sufficient size and
support the Commission’s policy of
129 Opinion

No. 486–B, 126 FERC ¶ 61,034 at P

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104.
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.
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.’’).

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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
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 riskcomparable 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
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
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.
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.

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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
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
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-ofservice 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.’’).

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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 riskappropriate Canadian entities that
otherwise satisfy the Commission’s
proxy group eligibility requirements.
B. Excluded Financial Models
1. Risk Premium
a. Background

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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
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 Que´bec &
Maritimes Pipelines Inc., March 2009, available at
http://www.regie-energie.qc.ca/audiences/3690-09/
RepDDRGM_3690-09/B-29_GM_Reasons-DecisionRH-1-2008_3690_30juin09.pdf (Trans Que´bec). In
that decision, the NEB revised its ratemaking policy
by adopting an after-tax weighted average cost-ofcapital 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.
146 Opinion No. 569, 169 FERC ¶ 61,129 at P 340.
147 Id. P 341.
148 Id. P 342.

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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 RTOwide 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
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
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
149 Opinion No. 569–A, 171 FERC ¶ 61,154 at PP
104–114.
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.

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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
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
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
151 Opinion No. 569, 169 FERC ¶ 61,129 at PP
200–201.
152 Id. PP 212–218.
153 Id. P 201 (quoting Hope, 320 U.S. at 603).
154 Id. P 172.
155 Id. P 201.
156 Id. PP 202, 211.
157 Opinion No. 569–A, 171 FERC ¶ 61,154 at PP
125–131.

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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
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
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
158 Id.

P 127.
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.
164 Hope, 320 U.S. at 603.

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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
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 highend 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
165 See

Opinion No. 569, 169 FERC ¶ 61,129 at P

201.
166 See

id. P 202.
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.’’).
167 See

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80. Conversely, the Commission has
applied specific outlier screens to
public utilities. Prior to Opinion No.
569, the Commission excluded as lowend 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 highend 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
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
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
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
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.
170 Opinion No. 569, 169 FERC ¶ 61,129 at P 387.
171 Id.
172 Id. P 388.
173 Id. P 375.
174 Id.

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Federal Register / Vol. 85, No. 102 / Wednesday, May 27, 2020 / Notices
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
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
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 brightline 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

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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 highend cost of equity estimates may cause
when the ROE is set at the midpoint of
the proxy group results.180 CAPP, by
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 highend outliers. Id.
176 Id. P 397.
177 Opinion No. 569–A, 171 FERC ¶ 61,154 at P
161.
178 Id. P 154.
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

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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
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
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
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.
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.
184 E.g., Opinion No. 546, 154 FERC ¶ 61,070 at
P 196.
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.

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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
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
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 industrywide 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.
187 Opinion

No. 569, 169 FERC ¶ 61,129 at P 395.
P 390.
189 Id. P 395.
188 Id.

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Federal Register / Vol. 85, No. 102 / Wednesday, May 27, 2020 / Notices

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
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.
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-ofequity 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.

ESTIMATED ANNUAL CHANGES TO BURDEN DUE TO DOCKET NO. PL19–4 196
[Figures may be rounded]
Number
of potential
respondents

Annual
number of
responses per
respondent

Total number
of responses

Average burden
hours & cost ($)
per response

Total annual
burden hours &
total annual cost
($)

Cost per
respondent ($)

(1)

(2)

(1) * (2) = (3)

(4)

(3) * (4) = (5)

(5) ÷ (1) = (6)

Updated ROE Study .......................

244

1

244

Refile FERC Form No. 6, page 700

244

1

Total Changes, Due to PL19–4

244

1

97. This additional one-time burden is
expected to be imposed in Year 1.
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
190 44

U.S.C. 3501–21.
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.
193 OMB’s regulations requiring approval of
certain collections of information are at 5 CFR 1320.

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191 Following

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244

187.5 hrs.;
$15,000.
0.5 hrs.; $40 .......

45,750 hrs.;
$3,660,000.
122 hrs.; $9,760

244

.............................

$3,669,760 .........

$15,000
40
15,040

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.
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: DataClearance@ferc.gov 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.

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.

196 We have conservatively assumed a 100%
voluntary response rate.
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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Federal Register / Vol. 85, No. 102 / Wednesday, May 27, 2020 / Notices
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 ferconlinesupport@ferc.gov,
or the Public Reference Room at (202)
502–8371, TTY (202) 502–8659. Email
the Public Reference Room at
public.referenceroom@ferc.gov.
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

DEPARTMENT OF ENERGY
Federal Energy Regulatory
Commission
[Docket Nos. CP20–454–000; CP14–518–
000]

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Golden Pass Pipeline LLC; Notice of
Application
Take notice that on May 13, 2020,
Golden Pass Pipeline LLC (Golden Pass
Pipeline), 811 Louisiana Street,
Houston, Texas 77002, filed an
application pursuant to section 7 of the
Natural Gas Act and part 157 of the
Commission’s regulations for authority
to amend its order issued on December
21, 2016, granting Golden Pass LNG
authority to site, construct and operate

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facilities for the exportation of liquefied
natural gas and granting Golden Pass
Pipeline authority to expand its existing
pipeline system (Compression
Relocation and Modification Project).
The Compression Relocation and
Modification Project consists of the
following: (1) Relocation of an
authorized compressor station from
Milepost 66 to Milepost 69 on the
Golden Pass Pipeline system; (2)
additional compression at the relocated
compressor station, (3) add a meter
station near Milepost 69 to support an
Interconnect with the proposed
interstate pipeline to be constructed and
operated by Enable Gulf Run
Transmission, LLC, (4) remove any bidirectional piping modification to the
Interconnect for Tennessee Gas Pipeline
Company, L.L.C. (Tennessee Gas), (5)
relocate looping facilities to reflect the
relocation of the compressor station and
the cancellation of Tennessee Gas as an
input source to Golden Pass Pipeline,
and (6) minor modifications to existing
interconnections at Milepost 66 and
Milepost 68, all as more fully described
in their application.
Any questions regarding this
application should be addressed to
Blaine Yamagata, Vice President and
General Counsel, Golden Pass LNG, 811
Louisiana Street, Suite 1500, Houston,
Texas 77002; or to Kevin M. Sweeney,
Law Office of Kevin M. Sweeney, 1625
K Street NW, Washington, DC 20006, by
telephone at (202) 609–7709.
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://
ferc.gov) using the eLibrary link. Enter
the docket number excluding the last
three digits in the docket number field
to access the document. 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. For
assistance, contact FERC at
FERCOnlineSupport@ferc.gov or call
toll-free, (886) 208–3676 or TYY, (202)
502–8659.
Pursuant to section 157.9 of the
Commission’s rules, 18 CFR 157.9,
within 90 days of this Notice the
Commission staff will either: Complete
its environmental assessment (EA) and
place it into the Commission’s public
record (eLibrary) for this proceeding; or
issue a Notice of Schedule for
Environmental Review. If a Notice of

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Schedule for Environmental Review is
issued, it will indicate, among other
milestones, the anticipated date for the
Commission staff’s issuance of the EA
for this proposal. The filing of the EA
in the Commission’s public record for
this proceeding or the issuance of a
Notice of Schedule for Environmental
Review will serve to notify federal and
state agencies of the timing for the
completion of all necessary reviews, and
the subsequent need to complete all
federal authorizations within 90 days of
the date of issuance of the EA.
There are two ways to become
involved in the Commission’s review of
this project. First, any person wishing to
obtain legal status by becoming a party
to the proceedings for this project
should, on or before the comment date
stated below file with the Federal
Energy Regulatory Commission, 888
First Street NE, Washington, DC 20426,
a motion to intervene in accordance
with the requirements of the
Commission’s Rules of Practice and
Procedure (18 CFR 385.214 or 385.211)
and the Regulations under the NGA (18
CFR 157.10). A person obtaining party
status will be placed on the service list
maintained by the Secretary of the
Commission and will receive copies of
all documents filed by the applicant and
by all other parties. A party must submit
3 copies of filings made in the
proceeding with the Commission and
must provide a copy to the applicant
and to every other party. Only parties to
the proceeding can ask for court review
of Commission orders in the proceeding.
However, a person does not have to
intervene in order to have comments
considered. The second way to
participate is by filing with the
Secretary of the Commission, as soon as
possible, an original and two copies of
comments in support of or in opposition
to this project. The Commission will
consider these comments in
determining the appropriate action to be
taken, but the filing of a comment alone
will not serve to make the filer a party
to the proceeding. The Commission’s
rules require that persons filing
comments in opposition to the project
provide copies of their protests only to
the party or parties directly involved in
the protest.
Persons who wish to comment only
on the environmental review of this
project should submit an original and
two copies of their comments to the
Secretary of the Commission.
Environmental commenters will be
placed on the Commission’s
environmental mailing list and will be
notified of any meetings associated with
the Commission’s environmental review
process. Environmental commenters

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