PL19-4, Notice of Inquiry, published in Fed. Reg.

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Federal Register / Vol. 84, No. 60 / Thursday, March 28, 2019 / Notices
in Klickitat County, Washington and
Sherman County, Oregon,
approximately 8 miles southeast of the
City of Goldendale. The project would
occupy 16.1 acres of lands administered
by the Bonneville Power
Administration.
g. Filed Pursuant to: 18 CFR 5.3 of the
Commission’s regulations.
h. Potential Applicant Contact: Erik
Steimle, Rye Development, 220 NW 8th
Avenue, Portland, Oregon 97209; (503)
998–0230; email—erik@
ryedevelopment.com.
i. FERC Contact: Michael Tust at (202)
502–6522; or email at michael.tust@
ferc.gov.
j. FFP Project 101, LLC (FFP) filed its
request to use the Traditional Licensing
Process on January 28, 2019. FFP
provided public notice of its request on
January 30, 2019 and January 31, 2019.
In a letter dated March 21, 2019, the
Director of the Division of Hydropower
Licensing approved FFP’s request to use
the Traditional Licensing Process.
k. With this notice, we are initiating
informal consultation with the U.S. Fish
and Wildlife Service and/or NOAA
Fisheries under section 7 of the
Endangered Species Act and the joint
agency regulations thereunder at 50 CFR
part 402; and NOAA Fisheries under
section 305(b) of the Magnuson-Stevens
Fishery Conservation and Management
Act and implementing regulations at 50
CFR 600.920. We are also initiating
consultation with the Washington State
Historic Preservation Officer and the
Oregon State Historic Preservation
Officer, as required by section 106,
National Historic Preservation Act, and
the implementing regulations of the
Advisory Council on Historic
Preservation at 36 CFR 800.2.
l. With this notice, we are designating
FFP as the Commission’s non-federal
representative for carrying out informal
consultation pursuant to section 7 of the
Endangered Species Act and section
305(b) of the Magnuson-Stevens Fishery
Conservation and Management Act; and
consultation pursuant to section 106 of
the National Historic Preservation Act.
m. FFP filed a Pre-Application
Document (PAD; including a proposed
process plan and schedule) with the
Commission, pursuant to 18 CFR 5.6 of
the Commission’s regulations.
n. A copy of the PAD is available for
review at the Commission in the Public
Reference Room or may be viewed on
the Commission’s website (http://
www.ferc.gov), using the ‘‘eLibrary’’
link. Enter the docket number,
excluding the last three digits in the
docket number field to access the
document. For assistance, contact FERC
Online Support at

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[email protected], (866)
208–3676 (toll free), or (202) 502–8659
(TTY). A copy is also available for
inspection and reproduction at the
address in paragraph h.
o. Register online at http://
www.ferc.gov/docs-filing/
esubscription.asp to be notified via
email of new filing and issuances
related to this or other pending projects.
For assistance, contact FERC Online
Support.
Dated: March 21, 2019.
Kimberly D. Bose,
Secretary.
[FR Doc. 2019–05903 Filed 3–27–19; 8:45 am]
BILLING CODE 6717–01–P

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, Department of Energy.
ACTION: Notice of inquiry.
AGENCY:

Following the decision of the
U.S. Court of Appeals for the District of
Columbia Circuit in Emera Maine v.
Federal Energy Regulatory Commission,
the Commission seeks 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. The Commission also
seeks comment on whether any changes
to its policies concerning public utility
ROEs should be applied to interstate
natural gas and oil pipelines.
DATES: Initial Comments are due June
26, 2019, and Reply Comments are due
July 26, 2019.
ADDRESSES: Comments, identified by
docket number, may be filed in the
following ways:
• Electronic Filing through http://
www.ferc.gov. Documents created
electronically using word processing
software should be filed in native
applications or print-to-PDF format and
not in a scanned format.
• Mail/Hand Delivery: Those unable
to file electronically may mail or handdeliver comments to: Federal Energy
Regulatory Commission, Secretary of the
Commission, 888 First Street NE,
Washington, DC 20426.
• Instructions: For detailed
instructions on submitting comments,
SUMMARY:

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see the Comment Procedures Section of
this document.
FOR FURTHER INFORMATION CONTACT:
Jeremy Hessler (Legal Information),
Office of the General Counsel, 888
First Street NE, Washington, DC
20426, (202) 502–8655,
[email protected].
Adam Pollock (Technical Information),
Office of Energy Market Regulation,
Federal Energy Regulatory
Commission, 888 First Street NE,
Washington, DC 20426, (202) 502–
8458, [email protected].
Scott Everngam (Technical Information),
Office of Energy Market Regulation,
Federal Energy Regulatory
Commission, 888 First Street NE,
Washington, DC 20426, (202) 502–
6614, [email protected].
Tony Dobbins (Technical Information),
Office of Energy Policy and
Innovation, Federal Energy Regulatory
Commission, 888 First Street NE,
Washington, DC 20426, (202) 502–
6630, [email protected].
SUPPLEMENTARY INFORMATION:
1. In this Notice of Inquiry (NOI), the
Commission seeks 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 rates charged by
public utilities. The Commission also
seeks comment on whether any changes
to its policies concerning public utility
ROEs should be applied to interstate
natural gas and oil pipelines.
2. This NOI follows the decision of
the U.S. Court of Appeals for the District
of Columbia Circuit (D.C. Circuit) in
Emera Maine v. FERC,1 reversing and
vacating Opinion No. 531.2 In that
decision, the court held, among other
things, that the Commission had failed
to justify its decision under section 206
of the Federal Power Act (FPA) 3 to set
the ROE of the New England
Transmission Owners 4 at the midpoint
of the upper half of the zone of
reasonableness produced by the twostep Discounted Cash Flow (DCF)
analysis. While the court did not
expressly question the Commission’s
1 854

F.3d 9 (DC Cir. 2017) (Emera Maine).
Mass. Attorney Gen. v. Bangor HydroElec. Co., Opinion No. 531, 147 FERC ¶ 61,234,
order on paper hearing, 149 FERC ¶ 61,032 (2014),
order on reh’g, 150 FERC ¶ 61,165 (2015).
3 16 U.S.C. 824e.
4 The New England Transmission Owners include
Bangor Hydro-Elec. Co.; Cent. Me. Power Co.; New
England Power Co. d/b/a Nat’l Grid; N.H.
Transmission LLC d/b/a NextEra; NSTAR Elect. &
Gas Corp.; Ne. Utilities Serv. Co.; United
Illuminating Co.; Unitil Energy Systems, Inc. and
Fitchburg Gas & Elec. Light Co.; and Vt. Transco,
LLC. Opinion No. 531, 147 FERC ¶ 61,234 at P 1
n.3.
2 Coakley,

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finding that anomalous capital market
conditions justified an ROE above the
midpoint of the DCF zone of
reasonableness, the court concluded
that the Commission failed to point to
record evidence supporting the
conclusion that its solution to the
anomalous capital market conditions—
setting the base ROE at the upper
midpoint rather than the midpoint—was
just and reasonable.5
3. The Commission recognizes the
potentially significant and widespread
effect of our ROE policies upon public
utilities. The importance of ROE policy
for public utilities extends beyond the
particular interests of the parties to the
Emera Maine proceeding. Accordingly,
this NOI seeks further information as
the Commission re-evaluates our ROE
policies following the Emera Maine
decision. Initial Comments are due June
26, 2019, and Reply Comments are due
July 26, 2019.
I. Background
A. The DCF Model
4. The Supreme Court has held 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.’’ 6 Since the
1980s, the Commission has used the
DCF model to develop a range of returns
earned on investments in companies
with corresponding risks for purposes of
determining the ROE for regulated
entities.
5. The DCF model was originally
developed in the 1950s as a method for
investors to estimate the value of
securities, including common stocks. It
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
With simplifying assumptions, the DCF
model results in the investor using the
following formula to determine share
price:
P = D/(k¥g),

where P is the price of the stock at the
relevant time, D is the current dividend,
k is the discount rate (or investors’
required return), and g is the expected
growth rate in dividends.
6. For ratemaking purposes, the
Commission rearranges the DCF formula
to solve for k, the discount rate, so that:
k = D/P + g.
Under the resulting DCF formula, the
investor’s required return is estimated to
equal current dividend yield (dividends
divided by share price) plus the
projected future growth rate of
dividends. The term ‘‘k’’ represents the
investor’s required return for investing
in the firm (i.e., the cost of equity).8 The
Commission’s practice has been to set a
regulated firm’s rate of return, or ‘‘r’’ to
equal ‘‘k’’ the investor’s required return
for investing in the firm.
7. During the decades that the
Commission has used the DCF model,
the Commission periodically has made
changes in its implementation of the
model with respect to the industries that
it regulates. In Opinion No. 531, the
Commission used the same two-step,
constant-growth DCF model in public
utility cases as it had used in natural gas
and oil pipeline cases for the last 20
years.9 For the dividend yield
component of that model, the
Commission derives a single, average
dividend yield based on the indicated
dividend and the average of the monthly
high and low stock prices over a sixmonth period.10 The Commission then
uses a two-step method to estimate a
single constant growth rate in
dividends.11
8. In order to project short-term
growth in dividends, the Commission
uses security analysts’ three-year to fiveyear earnings forecasts, as published by
the Institutional Brokers Estimate
System (IBES). The Commission has
held that earnings forecasts made by
investment analysts are the best
available estimates of short-term
dividend growth based on a finding that
they are relied on by investors when
making their investment decisions.12
9. The use of a long-term growth
estimate for dividends originated in the
8 See

Opinion No. 531, 147 FERC ¶ 61,234 at P

15.
5 Emera

Maine, 854 F.3d at 28–29.
Power Comm’n v. Hope Natural Gas Co.,
320 U.S. 591, 605 (1944) (Hope); see also Bluefield
Waterworks & Improvement Co. v. Pub. Serv.
Comm’n, 262 U.S. 679, 692–693 (1923) (Bluefield);
Duquesne Light Co. v. Barasch, 488 U.S. 299, 314
(1989).
7 Canadian Ass’n of Petroleum Producers v.
FERC, 254 F.3d 289, 293 (DC Cir. 2001); see also
Composition of Proxy Groups for Determining Gas
and Oil Pipeline Return on Equity, 123 FERC
¶ 61,048, at P 58 (2008) (Proxy Group Policy
Statement).

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9 Id.

P 8.
e.g., Portland Natural Gas Transmission
Sys., Opinion No. 510, 134 FERC ¶ 61,129, at PP
232–34 (2011).
11 Opinion No. 531, 147 FERC ¶ 61,234 at P 17.
12 See, e.g., Transcon. Gas Pipe Line Corp.,
Opinion No. 414–B, 85 FERC ¶ 61,323, at 62,269 &
n.34 (1998) (citing an article entitled ‘‘Using
Analysts’ Growth Forecasts to Estimate
Shareholders Required Rates of Return’’ in
Financial Management, Spring 1986, pages 58–67);
Proxy Group Policy Statement, 123 FERC ¶ 61,048
at PP 73–77.
10 See,

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Commission’s 1994 decision in Ozark
Gas Transmission System.13 In that
decision, the Commission explained:
In the constant growth DCF model used by
both parties in this proceeding, dividends are
expected to grow indefinitely at the rate of
(g). The indefinite future used by the DCF
model is 50 years or more . . . . While we
concede that it is more difficult to project
growth for many years from the present time,
we conclude that a projection limited to five
years, with no evidence of what is
anticipated beyond that point, is not
consistent with the DCF model and cannot be
relied on in a DCF analysis.14

In Opinion No. 396–B, issued in 1997,
the Commission held that the long-term
growth in the United States economy as
a whole, as measured by gross domestic
product (GDP), is the most reasonable
projection of long-term growth rates for
interstate natural gas pipelines.15 The
Commission stated, ‘‘[i]t is reasonable to
expect that, over the long-run, a
regulated firm will grow at the rate of
the average firm in the economy,
because regulation will generally
prevent the firm from being extremely
profitable during good periods, but also
protects it somewhat during bad
periods.’’ 16 The D.C. Circuit affirmed
the Commission’s decision to use GDP
to estimate long-term growth in
dividends.17
10. When the Commission first
required use of a long-term growth
estimate, the Commission averaged the
short-term IBES growth estimate with
the long-term GDP growth estimate in
determining the overall constant
dividend growth rate.18 However, in
1998, in Opinion No. 414–A, the
Commission changed the weighting
scheme in order to give two-thirds
weight to short-term forecasts and one13 68

FERC ¶ 61,032 (1994) (Ozark).
at 61,105. The Commission chose 50 years
to represent the indefinite future because the
present value of a one-dollar dividend received 50
years in the future and discounted at 12 percent is
less than one cent. Id. at n.32.
15 Opinion No. 396–B, 79 FERC at 62,382–83,
reh’g denied, Opinion No. 396–C, 81 FERC ¶ 61,036
(1997).
16 Id.
17 Williston Basin Interstate Pipeline Co., v. FERC,
165 F.3d 54, 64 (D.C. Cir. 1999), finding that ‘‘[t]he
testimony adduced at the hearing demonstrated that
major investment houses used an economy-wide
approach to project long-term growth, that such an
approach was supported by practical economic
considerations, and that existing industry-specific
approaches imperfectly reflected investor
expectations and made unfounded economic
assumptions.’’ Nonetheless, finding the record
evidence inadequate to support the Commission’s
use of certain GDP data, the court remanded the
case for further proceedings on this issue.
Subsequently, the Commission has used an average
of three GDP growth projections.
18 Opinion No. 396–B, 79 FERC at 62,383, reh’g
denied, Opinion No. 396–C, 81 FERC ¶ 61,036.
14 Id.

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third weight to long-term forecasts. The
Commission explained,
While determining the cost of equity
nevertheless requires that a long-term
evaluation be taken into account, long-term
projections are inherently more difficult to
make, and thus less reliable, than short-term
projections. Over a longer period, there is a
greater likelihood for unanticipated
developments to occur affecting the
projection. Given the greater reliability of the
short-term projection, we believe it is
appropriate to give it greater weight.
However, continuing to give some effect to
the long-term growth projection, will aid in
normalizing any distortions that might be
reflected in short-term data limited to a
narrow segment of the economy.19

The D.C. Circuit affirmed this twothirds/one-third weighting for
determining the overall dividend
growth estimate.20
11. Prior to Opinion No. 531, the
Commission determined public utility
ROEs using a one-step, constant-growth
DCF model, which considered only
short-term growth projections for a
public utility.21 In 2000, the
Commission decided not to adopt the
two-step DCF methodology for public
utilities, primarily because they were
only just beginning the process of
restructuring. Under those
circumstances, the Commission
determined that investors would be
unlikely to place much weight on longterm forecasts because the uncertainties
regarding the future were so great.22
However, in Opinion No. 531, the
Commission found that investor
uncertainty due to the type of changes
anticipated in 2000 had diminished.
Accordingly, the Commission
concluded that the time had come to
apply the same DCF methodology in
public utility cases as it utilizes in
natural gas and oil pipeline cases.23
Most importantly, the Commission
found that including a long-term
estimate of dividend growth in the
constant growth DCF model would
bring the public utility ROE approach
into full alignment with the underlying
19 Opinion

No. 414–A, 84 FERC at 61,423–24.
Ass’n of Petroleum Producers v.
FERC, 254 F.3d at 297. Since Opinion No. 414–A,
the Commission has made no changes in its twostep DCF methodology used for natural gas and oil
pipelines, except to require that, if a master limited
partnership (MLP) is included in the proxy group,
its long-term growth rate should be one-half the
GDP growth estimate. Proxy Group Policy
Statement, 123 FERC ¶ 61,048 at P 106. The
Commission explained that MLPs have less growth
potential than corporations, because they generally
distribute to partners an amount in excess of their
reported earnings. Id. P 12.
21 See Opinion No. 531, 147 FERC ¶ 61,234 at PP
24–31 (describing the one-step method).
22 Opinion No. 445, 92 FERC at 61,261–62.
23 Opinion No. 531, 147 FERC ¶ 61,234 at PP 35–
36.

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theory of the DCF model.24 As it found
with respect to natural gas and oil
pipelines, the Commission found that it
is reasonable to project that public
utilities, which transmit electricity to
supply energy to the national economy,
will have long-term growth consistent
with the growth of the economy as a
whole.25 The Commission also found
that the use of a long-term growth
projection will aid in normalizing any
distortions that might be reflected in
short-term data limited to a narrow
segment of the economy. Finally, using
the same long-term growth projection
for all public utilities produces a
narrower zone of reasonableness,
consistent with the fact different firms
in a regulated industry would not
ordinarily be expected to have widely
varying levels of profitability.
12. No party in the Opinion No. 531
proceeding objected to the
Commission’s adoption of the two-step
DCF model for public utilities, and the
Commission also applied that model,
without objection, in Opinion No. 551,
addressing a complaint that the MISO
Transmission Owners’ ROE is unjust
and unreasonable.26
B. Other Financial Models
13. Although the Commission has
used the DCF model to determine ROEs
for public utilities and natural gas and
oil pipelines since the 1980s, investors
use other financial models in addition
to the DCF model to evaluate
investments. In a number of recent
proceedings, discussed further below,
the Commission has considered certain
other financial models when
determining the just and reasonable
ROE for public utilities. These other
financial models include the Capital
Asset Pricing Model (CAPM), Expected
Earnings Model, and Risk Premium
method, which are described below.
24 Incorporating a long-term growth estimate in
the DCF methodology is consistent with the
underlying theory of the constant growth DCF
model because
from the standpoint of the DCF model that
extends into perpetuity, analysts’ horizons are too
short, typically five years. It is often unrealistic for
such growth to continue in perpetuity. A transition
must occur between the first stage of growth
forecast by analysts for the first five years and the
company’s long-term sustainable growth rate. . . .
It is useful to remember that eventually all company
growth rates, especially utility services growth
rates, converge to a level consistent with the growth
rate of the aggregate economy.
Roger A. Morin, New Regulatory Finance 308
(Public Utilities Reports, Inc. 2006) (Morin).
25 See Opinion No. 531, 147 FERC ¶ 61,234 at P
40.
26 Ass’n of Businesses Advocating Tariff Equity v.
Midcontinent Indep. Sys. Operator, Inc., 156 FERC
¶ 61,234 (2016).

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1. The CAPM Model
14. Investors use CAPM analysis as a
measure of the cost of equity relative to
risk.27 The CAPM methodology 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 the specific security.
Specifically, the CAPM methodology
estimates the cost of equity by taking the
‘‘risk-free rate’’ and adding to it the
‘‘market-risk premium’’ multiplied by
‘‘beta.’’ 28 The risk-free rate is
represented by a proxy, typically the
yield on 30-year U.S. Treasury bonds.29
Betas, which are published by several
commercial sources, measure a specific
stock’s risk relative to the market. The
market risk premium is calculated by
subtracting the risk-free rate from the
expected return. The expected return
can be estimated either using a
backward-looking approach, a forwardlooking approach, or a survey of
academics and investment
professionals.30 A CAPM analysis is
backward-looking if the expected return
is determined based on historical,
realized returns.31 A CAPM analysis is
forward-looking if the expected return is
based on a DCF analysis of a large
segment of the market.32 Thus, in a
forward-looking CAPM analysis, the
market Risk Premium is calculated by
subtracting the risk-free rate from the
result produced by the DCF analysis.33
2. Expected Earnings
15. A comparable earnings analysis is
a method of calculating the earnings an
investor expects to receive on the book
value of a particular stock. 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.34 The forward-looking
approach is often referred to as an
‘‘Expected Earnings’’ analysis. The
returns on book equity that investors
expect to receive from a group of
companies with risks comparable to
those of a particular utility are relevant
to determining that utility’s cost of
equity, because those returns on book
equity help investors determine the
27 Morin

at 146–147.
at 150.
29 Id. at 151.
30 Id. at 155–162.
31 Id. at 155–156.
32 Id. at 159–160.
33 Id. at 150, 155.
34 See Opinion No. 531–B, 150 FERC ¶ 61,165 at
P 125.
28 Id.

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opportunity cost of investing in that
particular utility instead of other
companies of comparable risk.35
3. Risk Premium
16. The Risk Premium methodology,
in which interest rates are a direct
input, is ‘‘based on the simple idea that
since investors in stocks take greater
risk than investors in bonds, the former
expect to earn a return on a stock
investment that reflects a ‘premium’
over and above the return they expect to
earn on a bond investment.’’ 36 As the
Commission found in Opinion No. 531,
investors’ required risk premiums
expand with low interest rates and
shrink at higher interest rates. The link
between interest rates and risk
premiums provides a helpful indicator
of how the interest rate environment
affects investors’ required rates of
return.
17. Multiple approaches have been
advanced to determine the equity risk
premium for a utility.37 For example, a
risk premium can be developed directly
by conducting a Risk Premium analysis
for the company at issue, or indirectly
by conducting a Risk Premium analysis
for the market as a whole and then
adjusting that result to reflect the risk of
the company at issue.38 Another
approach for the utility context is to
‘‘examin[e] 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.’’ 39

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C. Opinion Nos. 531 and 551 and
Anomalous Market Conditions
18. Since the financial crisis of 2008–
2009, the Commission has grappled
with whether the DCF model continues
to produce ROEs for public utilities
consistent with the Hope and Bluefield
capital attraction standards.40 In both
Opinion Nos. 531 and 551, the
Commission concluded that the capital
market conditions prevailing after the
financial crisis—in particular, the low
yields on bonds, including U.S.
Treasury bonds—rendered the
Commission less confident that a
mechanical application of the midpoint
of the DCF-produced zone of
reasonableness would provide a riskappropriate ROE, as required by Hope
and Bluefield. The Commission
therefore considered a series of
35 Id.

P 128.
No. 531, 147 FERC ¶ 61,234 at P 147
(citing Morin at 108).
37 See generally Morin at 107–130.
38 Id. at 110.
39 Id. at 123.
40 Hope, 320 U.S. 591; Bluefield, 262 U.S. 679.
36 Opinion

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alternative valuation methodologies
(i.e., CAPM analysis, Expected Earnings
analysis, and Risk Premium analysis), as
well as the ROEs allowed by state public
utility commissions, ‘‘to gain insight
into the potential impacts of these
unusual capital market conditions on
the appropriateness of using [the
midpoint of the DCF zone of
reasonableness].’’ 41 The Commission
concluded that the comparisons to the
other valuation methodologies
supported setting the New England
Transmission Owners’ ROE above the
midpoint of the DCF zone of
reasonableness. After determining that
the just and reasonable base ROE should
be above the midpoint, the Commission
stated that it has traditionally used
measures of central tendency to
determine an appropriate return in ROE
cases. Moreover, in cases involving
placement of the base ROE above the
central tendency of the zone of
reasonableness, the Commission has
used the central tendency of the top half
of the zone.42 Accordingly, in both
Opinion Nos. 531 and 551, the
Commission set the ROE at the
midpoint of the upper half of the zone
of reasonableness (upper midpoint).43 In
Opinion No. 531, the upper midpoint of
the 7.03 percent to 11.74 percent zone
of reasonableness was 10.57 percent.44
In Opinion No. 551, the upper midpoint
of the 7.23 percent to 11.35 percent zone
of reasonableness was 10.32 percent.45
D. The Emera Maine Decision
19. Various parties sought review of
Opinion No. 531 in the D.C. Circuit. The
New England Transmission Owners
argued that the Commission failed to
demonstrate that their existing 11.14
base ROE was unjust and unreasonable.
The customer representatives argued
that the Commission had failed to show
that the new 10.57 base ROE was just
and reasonable. In Emera Maine, the
D.C. Circuit agreed with both the New
England Transmission Owners and
customer representatives and vacated
and remanded Opinion No. 531 et seq.
20. As an initial matter, the court
rejected the New England Transmission
Owners’ argument that an ROE within
the DCF-produced zone of
reasonableness could not be deemed
No. 531, 147 FERC ¶ 61,234 at P 145.
PP 151–152; Opinion No. 551, 156 FERC
¶ 61,234 at PP 275–276.
43 The Commission sets the ROE for a group of
utilities at the midpoint or upper midpoint of the
zone of reasonableness, but the ROE for a single
entity at the median or upper median. See S.
California Edison Co. v. FERC, 717 F.3d 177, 181–
182 (D.C. Cir. 2013).
44 Opinion No. 531, 147 FERC ¶ 61,234 at P 142.
45 Opinion No. 551, 156 FERC ¶ 61,234 at P 67.

unjust and unreasonable. The court
explained that the zone of
reasonableness established by the DCF
is not ‘‘coextensive’’ with the
‘‘statutory’’ zone of reasonableness
envisioned by the FPA.46 Accordingly,
the court concluded that the fact that
the New England Transmission Owners’
existing ROE fell within the zone of
reasonableness produced by the DCF
did not necessarily indicate that it was
just and reasonable for the purposes of
the FPA.47
21. Nevertheless, the court agreed
with the New England Transmission
Owners that the Commission had not
adequately shown that their existing
ROE was unjust and unreasonable. The
court explained that the FPA’s statutory
‘‘zone of reasonableness creates a broad
range of potentially lawful ROEs rather
than a single just and reasonable ROE’’
and that whether a particular ROE is
unjust and unreasonable depends on the
‘‘particular circumstances of the
case.’’ 48 Thus, the fact that the New
England Transmission Owners’ existing
ROE did not equal the just and
reasonable ROE that the Commission
would have set using the current DCF
analysis inputs did not necessarily
indicate that the New England
Transmission Owners’ existing ROE fell
outside the statutory zone of
reasonableness.49 As such, the D.C.
Circuit concluded that Opinion No. 531
‘‘failed to include an actual finding as
to the lawfulness of [the New England]
Transmission Owners’ existing base
ROE’’ and that its conclusion that their
existing ROE was unjust and
unreasonable was itself arbitrary and
capricious.50
22. The court also agreed with the
customer representatives that the
Commission failed to adequately
demonstrate that the new base ROE it
established was just and reasonable. The
Court did not express concerns
regarding the Commission’s decision to
‘‘abandon its traditional use of the
midpoint of the zone of reasonableness
in setting [the New England]
Transmission Owners’ base ROE’’ based
on the anomalous capital market
conditions and its resulting evaluation
of alternative methodologies for

41 Opinion
42 Id.

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46 Emera

Maine, 854 F.3d at 22–23.
at 23.
48 Id. at 23, 26.
49 Id. at 27 (‘‘To satisfy its dual burden under
section 206, FERC was required to do more than
show that its single ROE analysis generated a new
just and reasonable ROE and conclusively declare
that, consequently, the existing ROE was per se
unjust and unreasonable.’’).
50 Id.
47 Id.

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calculating the cost of equity.51 The
court stated that ‘‘the alternative
benchmarks and additional record
evidence may have shown that some
upward adjustment was warranted.’’ 52
23. Nevertheless, the court concluded
that the Commission failed to point to
evidence in the record supporting the
conclusion that its solution to the
anomalous capital market conditions—
i.e., setting the base ROE at the upper
midpoint rather than at the midpoint—
was just and reasonable. The court
explained that the Commission
expressly did not rely on the alternative
methodologies to support its
determination that a 10.57 percent base
ROE was just and reasonable. The court
also observed that the Commission’s
explanation that it had previously set
the just and reasonable base ROE at a
measure of central tendency for the
upper part of the DCF-produced zone of
reasonableness was inapt because, in
those cases, the Commission had first
determined that those utilities were not
of average risk, whereas the Commission
found that the New England
Transmission Owners were of average
risk. The court therefore remanded the
proceeding so that the Commission
could further explain why the base ROE
it selected is just and reasonable.
E. Post-Emera Maine Proceedings

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24. Following the decision in Emera
Maine, the Commission issued two
orders proposing a methodology for
addressing the issues that were
remanded to the Commission in Emera
Maine and establishing a paper hearing
on whether and how this methodology
should apply to the four complaint
proceedings concerning both the New
England and MISO transmission
owners’ ROE.53 In those orders, the
Commission proposed to change its
approach to determining base ROE by
giving equal weight to four financial
models instead of primarily relying on
the DCF methodology. The Commission
stated that evidence indicates that
investors do not rely on any one model
to the exclusion of others. Therefore,
relying on multiple financial models
makes it more likely that the
Commission’s decision will accurately
51 Id. at 27; see also id. at 30 (‘‘[W]hile the
evidence in this case may have supported an
upward adjustment from the midpoint of the zone
of reasonableness, FERC failed to provide any
reasoned basis for selecting 10.57 percent as the
new base ROE.’’).
52 Id. at 30 (quotation marks omitted).
53 See Martha Coakley v. Bangor Hydro-Elec. Co.,
165 FERC ¶ 61,030 (2018) (Coakley Briefing Order);
Ass’n of Businesses Advocating Tariff Equity v.
Midcontinent Indep. Sys. Operator, Inc., 165 FERC
¶ 61,118 (2018) (MISO Briefing Order).

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reflect how investors make their
investment decisions.54
25. Specifically, the Commission
proposed to rely on three financial
models that produce zones of
reasonableness—the DCF model, CAPM
model, and Expected Earnings model—
to establish a composite zone of
reasonableness. The zone of
reasonableness produced by each model
would be given equal weight and
averaged to determine the composite
zone of reasonableness. The
Commission explained that the Risk
Premium model produces a single
numerical point rather than a range;
therefore, it cannot be used with the
other three financial models in
establishing a composite zone of
reasonableness.55 The Commission
proposed a framework for using that
composite zone of reasonableness in
evaluating whether an existing base
ROE remains just and reasonable.56
26. For purposes of establishing a new
just and reasonable base ROE when the
existing base ROE has been shown to be
unjust and unreasonable, the
Commission proposed relying on four
financial models—the DCF model,
CAPM model, Expected Earnings model,
and Risk Premium model—to produce
four separate base ROE estimates that
would then be averaged to produce a
specific just and reasonable base ROE.
27. The Commission established a
paper hearing in the Coakley and MISO
complaint proceedings 57 and directed
the participants in those proceedings to
submit briefs regarding this proposed
new approach and how to apply it to
those proceedings.58
II. Request for Comments
28. As part of ensuring that the
Commission continues to meet our
statutory obligations, the Commission,
on occasion, engages in public inquiry
to gauge whether there is a need to add
to, modify, or eliminate certain policies
or regulatory requirements. In this
proceeding, the Commission seeks
comments on potential modifications to
our approach to determining a just and
54 Coakley Briefing Order, 165 FERC ¶ 61,030 at
P 34; MISO Briefing Order, 165 FERC ¶ 61,118 at
P 36.
55 Coakley Briefing Order, 165 FERC ¶ 61,030 at
P 36; MISO Briefing Order, 165 FERC ¶ 61,118 at
P 38.
56 Coakley Briefing Order, 165 FERC ¶ 61,030 at
P 36; MISO Briefing Order, 165 FERC ¶ 61,118 at
P 38.
57 Coakley Briefing Order, 165 FERC ¶ 61,030 at
P 31; MISO Briefing Order, 165 FERC ¶ 61,118 at
P 20.
58 Coakley Briefing Order, 165 FERC ¶ 61,030 at
P 31; MISO Briefing Order, 165 FERC ¶ 61,118 at
P 20; see also Arkansas Pub. Serv. Comm’n, 165
FERC ¶ 61,119 (2018).

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reasonable ROE. Although the
Commission requested briefing on some
of the issues below in the Coakley and
MISO Briefing Orders, this proceeding
will provide all interested stakeholders
with the opportunity to comment on the
Commission’s ROE policy in light of the
decision in Emera Maine.
29. The Commission seeks comments
on eight general topics as part of this
inquiry: (A) The role of the
Commission’s base ROE in investment
decision-making and what objectives
should guide the Commission’s
approach; (B) whether uniform
application of our base ROE policy
across the electric, interstate natural gas
pipeline and oil pipeline industries is
appropriate and advisable; (C)
performance of the DCF model, (D)
proxy groups; (E) financial model
choice; (F) mismatch between marketbased ROE determinations and bookvalue rate base; (G) how the
Commission determines whether an
existing ROE is unjust and unreasonable
under the first prong of the FPA section
206; and (H) model mechanics and
implementation.
30. In the following sections, we
outline these eight topics and enumerate
questions that commenters may
consider in addressing each topic.
Commenters need not address every
topic or answer every question
enumerated below.
A. Role and Objectives of the
Commission’s Base ROE Policy
31. The Commission seeks comment
on the role of base ROE in investment
decision-making and what objectives
should guide the Commission’s
approach to our base ROE policy apart
from the basic Hope/Bluefield standard.
A1. To what extent would the ROE
methodology described in the Coakley
and MISO Briefing Orders impact the
predictability of ROE determinations
and the costs for market participants of
making or intervening in such
proceedings?
A2. How would using the ROE
methodology described in the Coakley
and MISO Briefing Orders affect an
investor’s ability to forecast the ROE the
Commission would establish in a
litigated proceeding and the ability of
participants to propose, contest, and
settle base ROEs as compared to using
only the DCF methodology?
A3. Currently, public utilities in
different Independent System Operators
(ISOs) or RTOs may receive different
ROEs, despite all using national proxy
groups, due primarily to differences in
when FPA section 205 or 206
proceedings were initiated. Are such
variations justified, and, if not, should

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the Commission consider applying the
same ROE to all utilities in RTOs/ISOs
based on the most recent proceeding?
A4. Should the ROE reflect the cost of
capital at the time of the investment or
be subject to adjustment to reflect the
contemporary ROE required by
investors?
A4.a. Should the Commission
consider a ‘‘vintage approach,’’ with
ROE fixed for the life of the asset at the
time that each asset was completed?
A4.b. Would such a ‘‘vintage
approach’’ need to be coupled with an
annual national default ROE for
investments made in that year, so as to
minimize the need for numerous annual
litigated ROE proceedings for each
public utility that made an investment
during that year? What procedure
should be used to determine such a
default ROE?
B. ROEs for Different CommissionRegulated Industries
32. The Commission seeks comment
on whether to apply a single ROE policy
across electric, interstate natural gas and
oil pipeline industries.
B1. In Opinion No. 531, the
Commission found that the same DCF
methodology should be used to
determine an ROE for all its regulated
industries, including public utilities, as
well as gas and oil pipelines. If the
Commission departs from our sole use
of a two-step DCF methodology for
public utilities, should the new method
or methods also be used to determine
natural gas and oil pipeline ROEs?
B2. The Risk Premium methodology
approved in Opinion Nos. 531 and 551
relied to a large extent on ROEs set forth
in numerous settlements involving
public utility formula rates approved by
the Commission over the preceding 15
or 20 years. Natural gas and oil
pipelines have stated rates and
settlements of their rate cases are
typically ‘‘black box’’ settlements that
do not specify an agreed-upon ROE.
How could the Risk Premium
methodology be implemented in natural
gas or oil pipeline rate cases where there
is no history of ROE settlements from
which to develop a risk premium study
of the type used in Opinion Nos. 531
and 551?
B3. Given the tendency of the
Expected Earnings methodology to
produce more high-end outliers than the
other methodologies, would there be a
sufficient number of natural gas and oil
pipeline proxy members to implement
the Expected Earnings methodology for
gas and oil pipelines?
B4. What, if any, differences between
public utilities on the one hand and
natural gas and oil pipelines on the

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other would justify using different
methodologies to determine their
ROEs? 59
C. Performance of the DCF Model
33. The Commission seeks comment
on the robustness of the DCF model over
time and under differing investment
conditions.
C1. The DCF model assumes stock
prices are equal to the present value of
projected future cash flows. Is there
evidence of situations when these
assumptions are inaccurate?
C2. Have current and projected proxy
company earnings over the last 10 to 20
years increased in a manner that would
justify any increases in their stock
prices over the same period, consistent
with DCF model assumptions?
C3. How does the DCF methodology
perform over a wide range of interest
rate conditions?
C3.a. What specific assumptions of
the DCF model, if any, do not work well
in low or high interest rate
environments?
C3.b. Is there evidence that the
volatility of price-to-earnings ratios over
the last 10 to 20 years, assumed to be
constant in the DCF methodology, has
been driven by the wide swings in
interest rates over this period? If so,
would the constant P/E assumption
impact the award of reasonable ROEs?
D. Proxy Groups
34. The Commission seeks comment
on the appropriate guidelines for proxy
group composition, elimination of
outliers, and placement of base ROE
within a zone of reasonableness.
D1. Should proxy groups for electric
utilities, as well as natural gas and oil
pipelines, consist only of companies
with corresponding regulated
businesses?
D1.a. For companies with a
combination of regulated and
unregulated businesses, should a
company be required to derive a certain
percentage of its revenues from the
applicable regulated business in order
for that company to be included in the
proxy group that is used to determine an
ROE for a company in that regulated
business?
D1.b. Are the corresponding proxy
groups sufficiently large given the
continued consolidation in the
industries?
D2. Should risk be considered both in
the proxy group selection and in the
59 See Trailblazer Pipeline Co. LLC, 166 FERC
¶ 61,141, at P 48 (2019) (setting for hearing the issue
of whether it would be appropriate to apply
alternatives to the DCF for natural gas pipelines and
whether appropriate data that would support those
alternatives are available).

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placement within the zone of
reasonableness?
D2.a. Should the Commission’s
approach to proxy group selection
change depending on which financial
models it considers when determining
the just and reasonable ROE and, if so,
how?
D3. Should the Commission consider
non-energy companies when selecting
proxy groups?
D3.a. What non-energy industries or
securities have comparable risk to
public utilities and natural gas and oil
pipelines, if any?
D3.b. Do certain non-energy
industries or securities feature fewer
outliers?
D4. What, if any, are appropriate highand low-end outlier tests?
D4.a. The Commission currently
excludes from the proxy group
companies whose ROE fails to exceed
the average 10-year bond yield by
approximately 100 basis points. Should
the low-end outlier test continue to be
based on a fixed value relative to the
costs of debt or (a) should it be based
on its value relative to the median (i.e.,
less than 50 percent of the median); or
(b) still reflect the cost of debt but vary
based on interest rates?
D4.b. How, if at all, should the
Commission’s approach to outliers vary
among different financial models?
D5. How, if at all, does the
Commission’s use of credit ratings in
ROE determinations incentivize public
utilities to behave in certain ways, such
as issuing more debt, and does this
affect public utilities’ credit ratings?
D6. What would be the impact of the
Commission modifying the credit rating
screen to include all investment-grade
utilities in the proxy group?
D7. To what extent do credit ratings
correspond to the ROE required by
investors?
D8. The Commission excludes from
the proxy group companies with merger
activity during the six-month study
period that is significant enough to
distort study inputs. Should the
Commission continue using our existing
merger screen?
D8.a. If so, should the Commission
revise its standards for what conduct
constitutes merger and acquisition
activity?
D9. What circumstances or factors, if
any, warrant an adjustment from the
midpoint/median to other points within
the zone of reasonableness (e.g., lower
or upper midpoint/median)?
D10. The Commission currently uses
midpoints to determine the central
tendency of the zone of reasonableness
when determining RTO-wide ROEs.

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Should the Commission adopt a policy
of using medians for this purpose?
D10.a. Would the use of multiple ROE
methodologies, as proposed in the
Coakley Briefing Order, undercut the
Commission’s current rationale for
using the midpoint in RTO-wide base
ROE?
D10.b. Should the size of the proxy
group be considered in this decision?
D11. Can the Commission continue to
construct proxy groups of sufficient size
for natural gas and oil pipeline
companies using the DCF methodology,
or in general for the alternative
methodologies, particularly considering
the increased amount of merger and
acquisition activity involving master
limited partnerships (MLPs) and the
multiple recent conversions of MLPs to
C-corporations?
E. Financial Model Choice
35. In addition to the DCF model, the
Commission seeks comment on other
financial models that investors use to
evaluate utility equities, the strengths
and weaknesses of each of those models,
and whether the Commission should
weigh certain financial models over
other models based on their respective
characteristics.
E1. What models do investors use to
evaluate utility equities?
E2. What role do current capital
market conditions play in the choice of
model used by investors to evaluate
utility equities?
E2.a. If capital market conditions
factor into the choice of model, how do
investors determine and evaluate those
conditions?
E3. Are any models thought to be
superior or inferior to others? If so,
why?
E4. How are alternative models
redundant or complementary with each
other and/or the DCF model?
E5. To what extent do alternative
models avoid any deficiencies of the
DCF model and/or operate better in
diverse capital market conditions?
E6. To the extent that investors use
multiple models, should the
Commission combine them in its
analysis or use the ‘‘best’’ one that
would apply in all market conditions?
E7. If the Commission were to
consider multiple models, how should
it weigh them?
E8. To what extent is it reasonable for
the Commission to use a simplified
version of a model that does not reflect
all the variables that investors consider?
E8.a. Is the use of a simplified model
justified for ease of administration and
predictability of result?
E9. How, if at all, should the
Commission consider state ROEs?

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E9.a. How and why do state ROEs
vary by state?
E9.b. How are certain state ROEs more
or less comparable to Commission
ROEs?
E10. If the Commission considers
state ROEs, how should it compare
FERC-jurisdictional transmission ROEs
with state ROEs that apply to utilities
that are (a) distribution and
transmission companies; or (b)
distribution, generation, and
transmission companies?
E11. To what extent, if any, should
the Commission exercise judgment in
using financial models to set ROEs
under various capital market
conditions?
F. Mismatch Between Market-Based
ROE Determinations and Book-Value
Rate Base
36. The DCF and CAPM models
determine a percentage ROE based on
market prices of the proxy companies.
That percentage ROE is then applied to
the book value of the rate base to
calculate the monetary ROE included in
a utility’s cost of service. For the last
three decades, the market-to-book ratios
of the companies that the Commission
uses in proxy groups have generally
been substantially in excess of one. The
Commission seeks comment on the
mismatch between market-based ROE
determinations and book-value rate base
and whether this mismatch is a
problem, and how the Commission
should address this issue.
F1. Does the mismatch between
market-based ROE determinations and a
book value rate base support current
market values? Is this mismatch a
problem?
F2. Why have most or all utility
market-to-book ratios consistently
exceeded one?
F3. How should the ROE level be set
relative to the cost of equity?
F4. Should the Commission revise our
use of these models to account for the
mismatch between market-based ROE
determinations and book-value rate
base? If so, how? For example, should
the Commission adjust the dividend
yield used in the DCF model to
represent a yield on book value rather
than a yield on stock price?
F5. Should the Commission consider
adjusting ROEs to account for market-tobook ratios above or below one? Would
doing so introduce circularity into
Commission ROEs by setting the ROE at
whatever level of earnings the market
expected, rather than making an

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independent assessment of the
appropriate ROE? 60
G. First Prong of ROE Determination
37. In the Coakley and MISO Briefing
Orders, the Commission proposed that,
in order to find an existing ROE unjust
and unreasonable under the first prong
of FPA section 206, the ROE must be
outside a range of presumptively just
and reasonable ROEs for a utility of its
risk profile, absent additional evidence
to the contrary. For average risk utilities,
the range of presumptively just and
reasonable ROEs would be the quartile
of the zone of reasonableness centered
on the central tendency of the overall
zone of reasonableness. For below or
above average risk utilities, that range
would be the quartile of the zone of
reasonableness centered on the central
tendency of the lower or upper half of
the zone of reasonableness, respectively.
The Commission seeks comment on
how the Commission determines
whether an existing ROE is unjust and
unreasonable under the first prong of
FPA section 206 and whether the
quartile approach that the Commission
proposed in the Coakley and MISO
Briefing Orders is reasonable.
G1. How should the Commission
determine if existing ROEs are just and
reasonable?
G2. Is the quartile approach that the
Commission proposed in the Coakley
and MISO Briefing Orders appropriate?
If not, how should the Commission
revise this methodology?
G3. When a successive complaint is
filed while the current ROE is being
adjudicated (i.e., a pancake complaint),
should the subsequent complainant be
required to make a prima facie showing
of sufficient change in market
conditions to meet the Coakley and
MISO Briefing Order’s proposed
determination of whether an existing
ROE remains just and reasonable? If so,
what type of information or showing
should the complainant provide to
demonstrate that market conditions
have changed, and what standard
should the Commission apply when
assessing whether to deny the
subsequent complaint without setting it
for hearing?
G4. In single utility rate cases, the
Commission determines the central
tendency of the zone of reasonableness
based on the median of the proxy group
ROEs. Is the approach outlined in the
Coakley and MISO briefing orders
appropriate in single utility rate cases
given that the proxy company ROEs
tend to cluster near the center of the
60 See Orange & Rockland Utilities, Inc., 44 FERC
¶ 61,253, at 61,952 (1998).

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zone of reasonableness, making the
middle quartile relatively narrow?
G4.a. Would it be reasonable to
determine the central tendencies of the
upper and lower halves of the zone of
reasonableness for single utilities based
on a midpoint analysis, so as to produce
approximately equal ranges of
presumptively just and reasonable ROEs
for below average, average, and above
average risk utilities?
H. Model Mechanics and
Implementation
38. The Commission seeks comment
on the mechanics and implementation
of the DCF, CAPM, Expected Earnings,
and Risk Premium models. Specifically,
the Commission seeks comment on
general issues that affect multiple
models, such as the underlying data that
the models rely on, and also seeks
comment on the mechanics specific to
each of the four respective models.

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1. General Issues/Issues That Affect
Multiple Models
H.1.1. Are IBES data a good proxy for
‘‘investor consensus?’’
H.1.1.a. If not, are there better
alternatives, such as Bloomberg, Zacks,
S&P Capital, Morningstar, and Value
Line?
H.1.1.b. Should the Commission
combine data from multiple sources?
H1.1.c. What weight, if any, should be
given to an estimate if the number and
identity of analysts contributing to the
estimate is not available?
H.1.2. To what extent does model risk
affect all ROE methodologies?
H.1.3. The DCF model incorporates
data at the parent/holding company
level (e.g., stock price). The Commission
adjudicates cases at the operating
company level, for which there is no
public data like stock prices, growth
rates, and betas. What impact does this
disparity have on the results of the DCF
and other models?
H.1.4. Should the Commission
continue to rely on the efficient market
hypothesis, which underlies the DCF
and CAPM models? Why or why not?
H.1.4.a. If yes, should the Commission
continue to employ outlier screens,
M&A screens, etc., for the DCF and
CAPM models since these models need
to incorporate all relevant information?
H.1.5. Should growth rates be based
on Value Line, IBES, or alternative
estimates?
H.1.6. Should the same growth rate
sources be used across models, if more
than one model is used to determine the
ROE?

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2. Model-Specific Questions

c. Expected Earnings

a. DCF

H.2.c.1. Should the use of utilities in
the proxy group for the Expected
Earnings model be predicated on the
Expected Earnings analysis being
forward-looking?
H.2.c.2. What, if any, concerns
regarding circularity are there with
using the Expected Earnings analysis to
determine the base ROE, as opposed to
using the analysis for corroborative
purposes?
H.2.c.2.i. If there are circularity
concerns, are there ways to mitigate
these concerns for the Expected
Earnings analysis? If these concerns
exist, are these concerns more
significant than those surrounding the
DCF methodology, which effectively
separates Expected Earnings and ROE
into its dividend yield and growth rate
subcomponents?

H.2.a.1. Should the Commission
continue to use a dividend DCF model
or should the Commission use a
different DCF model, for example, one
based on free cash flow?
H.2.a.2. Could terminal stock value be
used in place of long-term growth
projections? If so, how should terminal
stock value be determined?
H.2.a.3. Do investment analysts
project earnings/dividends growth
beyond five years, and if not, why not,
and is GDP an appropriate proxy for
long-term growth?
H.2.a.4. How should the Commission
weight short-term and long-term
earnings/dividend growth projections?
H.2.a.5. The Commission uses a
constant growth DCF model. Should the
Commission consider using a multistage DCF model? If so, how would the
Commission determine the length of
each stage of a proxy company’s
growth?
H.2.a.6. Are six months of average
high/low historical monthly stock prices
an appropriate measure for the current
stock price ‘‘P’’?
b. CAPM
H.2.b.1. If the market risk premium is
determined by applying the DCF
methodology to a representative market
index, should a long-term growth rate be
used, as in the Commission’s two-step
DCF methodology?
H.2.b.2. Beta is a measure of a
security’s risk relative to the broader
market, such as the S&P 500, not of its
absolute risk. Do CAPM’s assumptions
break down if both utility stocks and the
broader market become riskier over time
on an absolute basis, but the relative
increase in risk in utility stocks rises
more slowly?
H.2.b.3. What are appropriate data
sources for the beta value?
H.2.b.4. Should the Commission
employ more sophisticated versions of
the CAPM model that consider more
variables instead of only beta, such as
the Fama-French Model? 61
61 The Fama and French Model is an asset pricing
model that takes into consideration that value and
small-cap stocks outperform markets on a regular
basis. The model initially considered two factors in
addition to the CAPM model: The size risk and
value risk factors to the market risk factor in CAPM.
Later in 2015, two additional factors were added:
Profitability and investment. See generally Eugene
F. Fama, et al. ‘‘Common risk factors in the returns
on stocks and bonds,’’ Journal of Financial
Economics (1993); Eugene F. Fama, et al. ‘‘A FiveFactor Asset Pricing Model,’’ Journal of Financial
Economics (2015).

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d. Risk Premium
H.2.d.1. Should the analysis be
historical or forward-looking?
H.2.d.2. Is a Risk Premium analysis
compatible with a finding of anomalous
capital market conditions? Why or why
not?
H.2.d.3. Unlike the financial models
discussed above, the Risk Premium
analysis produces a single ROE rather
than a zone of reasonableness. Does this
characteristic require the Commission to
use the Risk Premium model differently
than the other models?
H.2.d.3.i. Is there a method by which
the Risk Premium ROE could be
adjusted upward for an above average
utility or downward for a below average
risk utility? If not, is it reasonable to
consider the results of a Risk Premium
analysis when determining the ROE of
an above or below average risk utility?
H.2.d.3.ii. Is it appropriate to use a
Risk Premium analysis when
conducting the first prong of the section
206 evaluation?
III. Comment Procedures
39. The Commission invites interested
persons to submit comments on the
matters and issues proposed in this
notice, including any related matters or
alternative proposals that commenters
may wish to discuss. Comments are due
June 26, 2019, and Reply Comments are
due July 26, 2019. Comments must refer
to Docket No. PL19–4–000, and must
include the commenter’s name, the
organization they represent, if
applicable, and their address.
40. The Commission encourages
comments to be filed electronically via
the eFiling link on the Commission’s
website at http://www.ferc.gov. The
Commission accepts most standard

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Federal Register / Vol. 84, No. 60 / Thursday, March 28, 2019 / Notices
word-processing formats. Documents
created electronically using wordprocessing software should be filed in
native applications or print-to-PDF
format and not in a scanned format.
Commenters filing electronically do not
need to make a paper filing.
41. Commenters that are not able to
file comments electronically must send
an original of their comments to:
Federal Energy Regulatory Commission,
Secretary of the Commission, 888 First
Street NE, Washington, DC 20426.
42. All comments will be placed in
the Commission’s public files and may
be viewed, printed, or downloaded
remotely as described in the Document
Availability section below. Commenters
on this proposal are not required to
serve copies of their comments on other
commenters.
IV. Document Availability

amozie on DSK9F9SC42PROD with NOTICES

43. 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) and in the Commission’s
Public Reference Room during normal
business hours (8:30 a.m. to 5:00 p.m.
eastern time) at 888 First Street NE,
Room 2A, Washington, DC 20426.
44. 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.
45. User assistance is available for
eLibrary and the Commission’s website
during normal business hours from the
Commission’s Online Support at (202)
502–6652 (toll free at 1–866–208–3676)
or email at [email protected],
or the Public Reference Room at (202)
502–8371, TTY (202) 502–8659. Email
the Public Reference Room at
[email protected].
By direction of the Commission.
Issued: March 21, 2019.
Nathaniel J. Davis, Sr.,
Deputy Secretary.
[FR Doc. 2019–05893 Filed 3–27–19; 8:45 am]
BILLING CODE 6717–01–P

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DEPARTMENT OF ENERGY
Federal Energy Regulatory
Commission
[Docket No. AD19–12–000]

Security Investments for Energy
Infrastructure Technical Conference;
Supplemental Notice of Technical
Conference
Take notice that the Federal Energy
Regulatory Commission (Commission)
and the United States Department of
Energy (DOE) will co-host a Security
Investments for Energy Infrastructure
Technical Conference (conference) on
Thursday, March 28, 2019, from 10:00
a.m. to 4:00 p.m. This Commissionerand DOE senior official-led conference
will be held in the Commission Meeting
Room at the Federal Energy Regulatory
Commission, 888 First Street NE,
Washington, DC 20426. The purpose of
the conference is to discuss current
cyber and physical security practices
used to protect energy infrastructure
and will explore how federal and state
authorities can provide incentives and
cost recovery for security investments in
energy infrastructure, particularly the
electric and natural gas sectors.
Attached is the final agenda for this
event with the confirmed list of
panelists.
The conference will be open and free
to the public; however, interested
attendees are encouraged to preregister
online at: https://www.ferc.gov/whatsnew/registration/03-28-19-form.asp. Inperson attendees should allow ample
time to pass through building security
procedures before the 10:00 a.m. start
time of the conference.
The Commission intends to solicit
post-technical conference comments
and will issue a public notice with
further directions following the
conclusion of the conference.
Information regarding the conference
will be posted on the Calendar of Events
on the Commission’s website, http://
www.ferc.gov, prior to the event. The
conference will also be webcast and
transcribed. Anyone with internet
access who desires to listen to this event
can do so by navigating to the Calendar
of Events at http://www.ferc.gov and
locating this event in the Calendar. The
event will contain a link to the webcast.
The Capitol Connection provides
technical support for webcasts and
offers the option of listening to the
meeting via phone-bridge for a fee. If
you have any questions, visit http://
www.CapitolConnection.org or call (703)
993–3100. Transcripts of the technical
conference will be available for a fee

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from Ace-Federal Reporters, Inc. at (202)
347–3700.
Commission conferences are
accessible under section 508 of the
Rehabilitation Act of 1973. For
accessibility accommodations, please
send an email to [email protected]
or call toll free 1 (866) 208–3372 (voice)
or (202) 502–8659 (TTY), or send a fax
to (202) 208–2106 with the required
accommodations.
For more information about this
technical conference, please contact
Carolyn Templeton by phone at (202)
502–8785 or by email at
[email protected]. For
information related to logistics, please
contact Sarah McKinley at (202) 502–
8368 or by email at sarah.mckinley@
ferc.gov.
Dated: March 21, 2019.
Nathaniel J. Davis, Sr.,
Deputy Secretary.

FERC/DOE Security Investments for
Energy Infrastructure Technical
Conference
Docket No. AD19–12–000
Thursday, March 28, 2019—10:00 a.m.–
4:00 p.m.
The Commission has a welldeveloped set of mandatory and
enforceable reliability standards that set
baseline protections for both cyber and
physical security of the bulk electric
system. Moreover, the Commission has
well established policies that allow for
the opportunity to recover prudently
incurred costs to comply with those
mandatory reliability standards. This
technical conference is aimed at better
understanding (1) the need for security
investments that go beyond those
measures already required by
mandatory reliability standards,
including in infrastructure not subject to
those standards (e.g., natural gas
pipelines); (2) how the costs of such
investments are or could be recovered;
and (3) whether additional incentives
for making such investments are
needed, and if so, how those incentives
should be designed.
10:00 a.m. Opening Remarks and
Introductions
10:30 a.m. Panel I: Cyber and Physical
Security, Best Practices, and Industry
and Government Engagement
Objectives: This panel will discuss
types of cyber and physical security
threats to energy infrastructure,
particularly electric transmission,
generation, and natural gas pipelines. In
addition, the panel will explore best
practices for cyber and physical security
mitigation beyond those measures
already required by mandatory

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