RESOLUTION
R-19-___
CITY HALL:
BY: COUNCILMEMBERS MORENO, WILLIAMS, GIARRUSSO, BANKS AND
BROSSETT

REVISED APPLICATION OF ENTERGY NEW ORLEANS, LLC FOR A CHANGE IN
ELECTRIC AND GAS RATES PURSUANT TO COUNCIL RESOLUTIONS R-15-194
AND R-17-504 AND FOR RELATED RELIEF
RESOLUTION AND ORDER
DOCKET NO. UD-18-07
WHEREAS, pursuant to the Constitution of the State of Louisiana and the Home Rule
Charter of the City of New Orleans (“Charter”), the Council of the City of New Orleans
(“Council”) is the governmental body with the power of supervision, regulation, and control over
public utilities providing service within the City of New Orleans; and
WHEREAS, pursuant to its powers of supervision, regulation and control over public
utilities, the Council is responsible for fixing and changing rates and charges of public utilities and
making all necessary rules and regulations to govern applications for the fixing and changing of
rates and charges of public utilities; and
WHEREAS, Entergy New Orleans, LLC (“ENO” or “Company”) provides retail electric
service and gas within the City of New Orleans; and
WHEREAS, Council Resolution No. R-17-228 directed ENO to exclude certain costs and
accounting entries related to its 2017 internal restructuring from its cost of service studies in its
2018 rate case filing (i.e., the “Application”); and

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 WHEREAS, Council Resolution No. R-17-504 directed ENO to include in its 2018 rate
case filing certain information, the provision of which as part of ENO’s filing, the Council expects
may serve in the interest of economy, efficiency, and a reduction in regulatory costs as it reviews
the Application; and
WHEREAS, Council Resolution No. R-18-97 directed ENO to include as part of its 2018
rate case filing (i.e. the Application) a green pricing proposal under which customers may
voluntarily choose to have some or all of their electricity supplied by renewable resources; and
WHEREAS, on July 31, 2018, ENO filed its initial Application of Entergy New Orleans,
LLC for a Change in Electric and Gas Rates Pursuant to Council Resolutions R-15-194 and R17-504 and For Related Relief (“Initial Rate Filing”); and
INITIAL RATE FILING
WHEREAS, ENO’s Initial Rate Filing proposed a change in electric and gas rates and
new rate schedules applicable to electric and gas service; and
WHEREAS, ENO’s Initial Rate Filing proposed electric rates that would overall decrease
its revenues by approximately $20 million per year and proposed gas rates that would overall
decrease its revenues by approximately $0.13 million per year; and
WHEREAS, according to the Company, the total net effects of the initially proposed
electric rate changes on typical monthly electric bills are summarized in the following table:

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 Estimated Typical Monthly Electric Bill
Summer ($)
Energy Demand
Present
Proposed
Customer Type
(kWh)
(kW)
Rate
Rate
Residential – Legacy
1,000
$122.11
$126.57
Residential – Algiers
1,000
$104.28
$126.68
Small Electric – Legacy
10
1,825
$242.69
$257.62
Small Electric – Algiers
10
1,825
$265.13
$260.08
Large Electric – Legacy
250
91,250 $9,552.67 $8,916.46
Large Electric, HLF - Algiers
250
91,250 $8,439.13 $9,081.85

Difference
$4.46
$22.40
$14.93
($5.05)
($638.21)
$642.72

and
WHEREAS, with regard to the electric rate increase initially proposed for Algiers
residential customers, the Council noted its disappointment and serious concern regarding ENO’s
estimated bill impact on Algiers residential customers. One of the primary functions of the
Council in its utility regulatory capacity is the establishment of just and reasonable rates. The
Council’s initial reaction is that such a significant estimated increase will result in rate shock that
is patently unacceptable and may be found to be unjust and unreasonable as filed without some
form of viable mitigation measures. Accordingly, the Council indicated its intent to direct ENO
to file a supplement to its Initial Rate Filing with proposed mitigation measures for the substantial
Algiers residential rate increase; and
WHEREAS, in a letter dated August 15, 2018, Roderick K. West, Entergy Group
President of Utility Operations, explained that ENO had decided to withdraw its Initial Rate
Filing, explaining that the decision to withdraw the Initial Rate Filing was in “response to the
thoughtful feedback that Entergy New Orleans has received from members of the Council of the
City of New Orleans and the Council’s legal and technical Advisors, particularly with regard to
the need to develop a better path toward a single rate structure for all customers of Entergy New
Orleans, both those residing on the East Bank of New Orleans and those residing in Algiers” and
noted that ENO would refile the rate case in September; and
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 ENO’S REVISED RATE APPLICATION
WHEREAS, on September 21, 2018, ENO refiled its rate case, Revised Application of
Entergy New Orleans, LLC for a Change in Electric and Gas Rates Pursuant to Council
Resolutions R-15-194 and R-17-504 and For Related Relief (“Revised Application”); and
WHEREAS, the Revised Application states that ENO’s request has three principal
components: (1) a new combined electric rate structure, which realigns the revenue requirement
associated with non-fuel capacity and long-term service agreements (“LTSA”) from certain riders
to base revenue and will recover the cost of Advanced Metering Infrastructure (“AMI”); (2)
contemporaneous cost recovery riders for investments in energy efficiency/demand response (also
referred to as demand-side management or “DSM”), incremental changes in capacity/LTSA costs,
grid modernization investments, and for Gas Infrastructure Replacement investments and related
costs; and (3) Formula Rate Plans (“FRP”), one for Electric operations which incorporates a
proposed decoupling mechanism as required by the Council, and one for Gas operations; and
WHEREAS, ENO’s Revised Application in this proceeding is a full base rate case with
test years ending December 31, 2017 (Period I) and December 31, 2018 (Period II); and
WHEREAS, the Revised Application includes ENO’s request for a change in electric and
gas rates and new rate schedules applicable to electric and gas service; and
WHEREAS, ENO’s Revised Application proposed electric rates would overall decrease
its revenues by approximately $20 million per year and proposed gas rates would overall decrease
its revenues by approximately $0.142 million per year; and
WHEREAS, according to the Company, the net effects of these proposed electric rate
changes on typical monthly electric bills are summarized in the following table:

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 Estimated Typical Monthly Electric Bill
(Summer)
($)
Energy Demand Present
Phase I
(kWh) (kW)
Rate
Proposed
Rate August
2019
Customer Type
Residential Legacy
Residential Algiers
Small Electric Legacy
Small Electric Algiers
Large Electric Legacy
Lg. Elec. - HLF Algiers

1000
1000
1,825
1,825
91,250
91,250

10
10
250
250

$ 122.11
$ 104.28
$ 242.69
$ 265.13
$9,552.67
$8,439.13

$124.13
$107.93
$252.62
$247.27
$9,213.95
$9,236.05

Phase II
Proposed
Rate September
2021

Difference
Difference
$2.02
$124.13
$-0$3.65
$111.69
$3.76
$9.93
$252.62
$-0$247.27
$-0($17.86)
$-0($338.72) $9,213.95
$796.92 $9,192.81 ($43.24)

and
WHEREAS, according to the Company, the net effects of these proposed gas rate changes
on typical monthly gas bills are summarized in the below table:
Estimated Typical Monthly Gas
(Winter)
($)
Customer Type

Consumption

Present Rate

Proposed Rate

Difference

Residential

100 ccf

$82.11

$81.24

($0.87)

Commercial

50 mcf

$428.66

$414.00

($14.66)

$6,876.56

($67.53)

Industrial

1,000 mcf

$6,944.09

and
ENO’S REQUEST FOR RELIEF
WHEREAS, ENO requests the following relief in its Application:
1. That the Council issue an order confirming that Entergy New Orleans’ filing, including its
Application is in substantial compliance with the Minimum/Standard Filing
Requirements;
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 2. That the Council direct that notice of all matters in these proceedings be sent to Gary E.
Huntley and Alyssa Maurice-Anderson, as representatives of ENO;
3. That the Council find that the change in electric and gas rates described herein, but more
particularly and specifically described in the testimony and exhibits of the witnesses
attached hereto and made part hereof, is in the public interest, will result in just and
reasonable rates and, subject to the terms and conditions to be established hereby, fully
complies with Louisiana law and the ordinances of the Council;
4. That the Council take official action to grant the Company’s request for a change in
electric and gas rates, and such other specific requests for which the Company seeks
approval herein, including but not limited to the following:
a. approving the Company’s proposed depreciation rates so that the return of capital
may be synchronized to the service life of the plant used to provide customers
electric service;
b. approving the Company’s proposed electric and natural gas formula rate plans;
c. approving the other new and revised riders proposed by ENO;
d. approving after receiving the Company’s supplemental application, the new
customer service and billing offerings proposed by the Company;
e.

approving the withdrawal of certain rate schedules, as well as the new and
modified rate schedules;

f. approving ENO’s recovery of costs associated with the five grid modernization
projects proposed in the filing for such projects closing to plant after December
31, 2019, and approves the regulatory review process proposed for use with future
grid modernization projects;

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 g.

approving the Company’s proposed modifications to ENO’s Service Regulations
Applicable to Electric and Gas Service;

5. That the Council adopt for application in this proceeding its Official Protective Order as
set forth in Resolution No. R-07-432, or provide for such other appropriate protection for
any confidential information to be produced in this proceeding;
6. That the Council approve the proposed procedural schedule allowing for ENO to provide
supplemental information regarding its new offerings;
7. That the Council grant all other Orders and decrees as may be necessary, and for all general
and equitable relief that the law and the nature of the case may permit; and
MINIMUM FILING REQUIREMENTS
WHEREAS, pursuant to Chapter 158 of the Code of the City of New Orleans (“City
Code”), when a utility files an application to change rates or services, the application must satisfy
certain Minimum Filing Requirements (“MFR”), which requirements provide the information
necessary to permit a thorough analysis of the utility’s application; and
WHEREAS, ENO states that its Revised Application comports with the MFRs and
requests an order confirming that ENO’s filing, including its Revised Application is in substantial
compliance with the MFRs. However, out of abundance of caution, to the extent that the Council
determines that ENO’s filing does not meet the referenced MFRs, pursuant to Section 158-48, of
the City Code, the Company requests waiver of such requirements. Alternatively, ENO requests
that a reasonable opportunity to remedy any such deficiencies be granted by the Council; and
WHEREAS, the Council, in Resolution No. R-18-434, stated that it wished for ENO to
comply with the MFRs and will provide ENO a reasonable opportunity to remedy any deficiencies
thereof. Further, the Council directed the parties to the instant docket to attempt to amicably

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 resolve any disputes as to whether the Revised Application is in compliance with respect to the
MFRs; and
PROCEDURAL MATTERS
WHEREAS, Section 158-91 of the City Code establishes that the Council shall have 12
months from its acceptance of the utility’s filing within which to review the filing and to render a
determination as to the proper rates to be charged by the utility and if the Council has not made
this determination by 12 months plus one day after the date of acceptance, the rates as submitted
by the utility in the accepted filing shall become effective subject to refund; and
WHEREAS, ENO addressed the Council’s concern that had ENO not withdrawn its initial
rate filing and the case been determined within applicable time limits under Section 158-91 of the
Code of the City of New Orleans, the proposed decrease in ENO’s rates would become effective
with the first billing cycle of August 2019. In order to ensure that customers receive potentially
lower rates at that same time but without compressing the Council’s twelve-month review period,
ENO commits that rates ultimately approved by the Council in this proceeding will be effective as
of the first billing cycle August 2019 even though a Council decision may not be issued by that
time. The Council will direct ENO to make such necessary adjustments to customer bills to reflect
the appropriate amounts due to reflect the approved rates retroactively to the first billing cycle of
August 2019; and
WHEREAS, in Resolution No. R-18-434, the Council established a procedural schedule
to allow the parties to this proceeding to rigorously investigate the Revised Application, conduct
discovery, file testimony and otherwise establish a record upon which the Council may rely to
render a determination as to the proper rates to be charged by ENO; and

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 WHEREAS, several parties timely intervened in the docket including the Alliance for
Affordable Energy (“AAE”), Air Products and Chemicals, Inc. (“Air Products”), Building
Science Innovators, LLC (“BSI”), City of New Orleans, Sewerage and Water Board of New
Orleans (“SWB”), Crescent City Power Users Group (“CCPUG”), Justice and Beyond, Sierra
Club, and 350 New Orleans; and
WHEREAS, numerous parties evaluated various aspects of the case by issuing hundreds
of discovery requests, reviewing thousands of pages of responses, and conducting oral depositions
of multiple experts; and
WHEREAS, ENO, AAE, Air Products, CCPUG, BSI, and the Council’s Advisors
actively participated in the docket and a total of thirty-three (33) expert witnesses provided sworn
pre-filed testimony in the case in support of their respective positions; and
WHEREAS, a five-day evidentiary hearing was conducted on June 17, 2019 through June
21, 2019, before the Honorable Jeffrey S. Gulin wherein parties were allowed to cross examine
other parties’ witnesses and introduce additional evidence into the record; and
WHEREAS, several parties filed initial briefs and reply briefs outlining their positions
and setting forth their legal arguments for the Council’s consideration; and
WHEREAS, the Council has reviewed ENO’s Revised Application, the positions of the
parties and the evidence presented in the voluminous record certified in this proceeding and
resolve the issues presented as follows; and

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 RETURN ON EQUITY (“ROE”)
WHEREAS, in utility ratemaking, the primary objective is to allow the utility company
sufficient revenues to meet its operating expenses, provide its shareholders with a reasonable rate
of return (“ROR”), and attract new capital;1 and
WHEREAS, the ratemaking process involves a complicated set of factors under which
the regulator approves rate increases or requires rate decreases for each customer class. Retail
rates should allow the utility the opportunity to recover prudently incurred operating and
maintenance expenses, taxes, and a fair return on investment that is used and useful in providing
utility services;2 and
WHEREAS, the legal standard for determining what is a fair ROR was articulated in two
seminal cases: Federal Power Comm’n v. Hope Natural Gas Co.3 and Bluefield Waterworks &
Improvements Co. v. Public Service Commission of W. Virginia.4 In Bluefield, the Court observed:
What annual rate will constitute just compensation depends upon many
circumstances, and must be determined by the exercise of a fair and enlightened
judgment, having regard to all relevant facts. A public utility is entitled to such
rates as will permit it to earn a return on the value of the property which it employs
for the convenience of the public equal to that generally being made at the same
time and in the same general part of the country on investments in other business
undertakings which are attended by corresponding risks and uncertainties; but it
has no constitutional right to profits such as are realized or anticipated in
highly profitable enterprises or speculative ventures. The return should be
reasonably sufficient to assure confidence in the financial soundness of the
utility and should be adequate, under efficient and economical management,
to maintain and support its credit and enable it to raise the money necessary
for the proper discharge of its public duties. A rate of return may be reasonable
at one time and become too high or too low by changes affecting opportunities for

1

Gordon v. Council of City of New Orleans, 9 So. 3d at 73; citing Cent. Louisiana Elec. Co. v. Louisiana Pub. Serv.
Comm’n, 508 So. 2d 1361, 1364 (La. 1987); S. Cent. Bell Tel. Co. v. Louisiana Pub. Serv. Comm’n, 352 So. 2d 964,
967 (La. 1977).
2
Id.
3
Federal Power Comm’n v. Hope Natural Gas Co., 320 U.S. 591, 64 S. Ct. 281, 88 L. Ed. 333 (1944) (“Hope”).
4
Bluefield Water Works & Improvement Co. v. Pub. Serv. Comm’n of W. Va., 262 U.S. 679, 43 S. Ct. 675, 67 L. Ed.
1176 (1923) (“Bluefield”).

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 investment, the money market and business conditions generally. 5 (Emphasis
added).
In Hope, the Court reiterated these principles, stating:
Rates which enable the company to operate successfully, to maintain its
financial integrity, to attract capital, and to compensate its investors for the
risks assumed certainly cannot be condemned as invalid, ....6 (Emphasis added);
and
WHEREAS, as a general proposition, these cases hold that the rate-making process rests
on a balancing of interests between the investors and the consumers;7 and
WHEREAS, the method used to balance the interests of the investors and the consumers
is well established. The initial determination that must be made is the utility’s future revenue
requirement;8 and
WHEREAS, as a guide to such a determination, data is generally gathered from some 12month period taken as a “test year.”9 Customarily, the test year selected is the most recent annual
period from which actual operating data is available. The data gathered is then used to calculate
the following four variables:
1. The amount of revenues generated under the present rate structure.
2. The operating expenses, including maintenance, depreciation, and taxes, incurred to
produce revenues.
3. The rate base, i.e., the value of the property, plant, and equipment, (less accumulated
depreciation) and related non-tangible assets, which provide the service, and on which
a return should be earned.

5

Id. at 692-93, 43 S. Ct. at 679.
Hope, 320 U.S. at 605, 64 S. Ct. at 289.
7
Cent. Louisiana Elec. Co. v. Louisiana Pub. Serv. Comm’n, 508 So. 2d at 1365.
8
Id.
9
Id. citing James C. Bonbright, et al., Principles of Public Utility Rates 150, n.7 (1961).
6

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 4. The rate of return, a percentage figure which, when applied to the rate base, will
generate revenues sufficient to cover costs and give investors a fair return on their
investment;10 and
WHEREAS, ENO’s allowed return on investment can be regarded as its Weighted
Average Cost of Capital (“WACC”), which is constituted as a weighting of the return on long
term debt components and an allowed-ROE, which can be regarded as the WACC component
allowing ENO a profit;11 and
WHEREAS, accepted regulatory principles and the U.S. Supreme Court’s Hope and
Bluefield decisions provide that ENO be allowed a return on its investment that:
1. is comparable to that being earned by other companies with comparable risks,
2. is sufficient to assure confidence in its financial soundness, and
3. is adequate to maintain its credit worthiness and enable it to raise necessary
capital;12 and
WHEREAS, the Council is not obligated to employ any specific methodology when
setting ENO’s rates, however, both ENO in its Application and the Advisors in their direct
testimony calculate their respective proposed rates based on allowing the opportunity for recovery
of prudently incurred operating costs, plus a fair return on investment to include a reasonable
allowed-ROE, which is an accepted methodology;13 and
WHEREAS, further, for many years, the Council has repeatedly acknowledged these
ratemaking principles set forth in Hope and Bluefield in a variety of rate proceedings;14 and

Cent. Louisiana Elec. Co. v. Louisiana Pub. Serv. Comm’n, 508 So. 2d at 1365.
Advisors’ Initial Brief at 26.
12
Bluefield, 262 U.S. at 692; and Hope, 320 U.S. 591.
13
Advisors’ Initial Brief at 27.
14
Resolution Nos. R-03-272, at 11-12 (resolving rate case Docket No. UD-01-04), R-09-136, at 10 (resolving rate
case Docket No. UD-08-03), and R-14-278, at 17-18 (resolving rate case Docket No. UD-13-01), all reference and
accept these regulatory ratemaking principles regarding the appropriate allowed return on ENO’s investments.
10
11

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 WHEREAS, these variables are then used to determine the “return” (i.e., ROE) that is
available to be distributed to the utility’s investors and the “actual rate of return” presently being
earned by the utility.15 The “return” or earnings is equal to the utility’s revenues less its operating
expenses, exclusive of interest.16 The ratio of the utility’s return to its rate base is equal to its
actual ROR;17 and
WHEREAS, as part of the Council’s ratemaking authority when setting ENO’s retail rates
in this proceeding, the concept of ROR specifically means an appropriate WACC whose
components are long-term debt total cost and ROE;18 and
WHEREAS, in its Application, ENO asserts that the Company’s ROE lies in the range of
10.25% to 11.25%.19 Within that range, the Company considers 10.75% to be the best estimate of
ENO’s Cost of Equity and recommends that the Council adopt a 10.75% ROE;20 and
WHEREAS, ENO contends that Mr. Hevert is the only witness offering an opinion in this
proceeding on ENO’s estimated ROE that performed a comprehensive analysis that fairly
measured ENO’s risk;21 and
WHEREAS, the Company contends that Mr. Hevert’s recommendation results from a
balanced approach considering the relative strengths and weaknesses of multiple analytical
methodologies as well as considerable empirical and qualitative information in analyzing and
giving appropriate weight to their results;22 and

15

Bluefield, 262 U.S. 692 and Hope, 320 U.S. 591.
Id.
17
Id.
18
Advisors’ Initial Brief at 27.
19
ENO Initial Brief at 44.
20
Id.
21
Id. at 41.
22
Id.
16

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 WHEREAS, Specifically, Mr. Hevert conducted analyses that included the Discounted
Cash Flow (“DCF”) model, including the Constant Growth and Multi-Stage forms; the Capital
Asset Pricing Model (“CAPM”); the Bond Yield Plus Risk Premium approach; and the Expected
Earnings model;23 and
WHEREAS, ENO argues that the opposing witnesses give considerable weight to the DCF
method, even though it produces ROE estimates in some cases more than 150 basis points below
the returns authorized for other electric utilities;24 and
WHEREAS, ENO also proposed a Reliability Incentive Mechanism (“RIM”) Plan, which
would affect the base rates to be set in this proceeding and afterwards through the proposed Electric
FRP.25 Under the RIM Plan, ENO proposed that the earnings component of its electric base rates
be correlated to reliability performance through an adjusted ROE formula, included in the FRP
that features a Reliability Adjustment.26 Under the Company’s RIM Plan,27 ENO is requesting
that for the purpose of initially setting rates resulting from this proceeding that a ROE of 10.50%
be implemented on its electric Cost of Service based on a negative adjustment of 25 basis points
applied to the proposed ROE of 10.75% recommended by Company witness Robert B. Hevert.28
Through the Company’s proposed electric FRP as described by Company witness Phillip B.
Gillam, ENO seeks an opportunity to achieve enhanced returns commensurate with the 10.75%
recommended by Mr. Hevert as ENO realizes increases in electric service reliability.29 According

23

Id. at 42.
Id.
25
Ex. No. ENO-55 at 2.
26
Id.
27
Ex. No. ENO-2 at 23:1-30:5 (HSPM).
28
Ex. No. ENO-55 at 21.
29
Id. at 21-22.
24

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 to ENO, the Company should be allowed to earn more than its baseline ROE under the RIM Plan
as a matter of fairness and maintaining a constructive regulatory environment;30 and
WHEREAS, the Advisors recommend that the Council adopt an allowed-ROE of 8.93%
for both electric and gas based on the comprehensive and persuasive testimony and multiple
analyses of two expert witnesses in this proceeding;31 and
WHEREAS, the Advisors’ assert that their recommendation is based on the evaluation of
market-based and accepted analytical methodologies that demonstrate that an 8.93% ROE
represents a fair return to ENO;32 and
WHEREAS, while an 8.93% ROE is in-line with the recommendations of the Intervenor
witnesses (i.e., 9.35%), the Advisors have pointed out that ENO’s ROE proposal of 10.75% is an
outlier among the other recommended ROEs in this proceeding;33 and
WHEREAS, although the Company attempts to rely on numerous authorized ROEs in
other jurisdictions to argue that the Advisors’ and other Intervenors’ recommendations are
unreasonable, the Advisors argue that the ROEs cited in Mr. Hevert’s testimony actually weakens
ENO’s argument for an authorized ROE of 10.75%.34 The Advisors also argue that as evidenced
in his own chart, the overwhelming majority of authorized ROEs represented in Mr. Hevert’s
testimony are significantly lower than ENO’s requested ROE of 10.75% in this proceeding; 35 and
WHEREAS, ENO’s claims that witness Hevert’s “analysis indicated a range of 10.25%
to 11.25% for equity investors’ required ROE for investment in integrated electric utilities.”36 The

30

Ex. No. ENO-2 at 27:14-16 (HSPM).
Advisors’ Initial Brief at 31.
32
Id.
33
Ex. No. ADV-8 at 18:14-19:4.
34
Advisors Brief at 28; ENO-29 at 6, Chart 2.
35
Id.
36
ENO Initial Brief at 44.
31

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 Advisors assert that this claim is largely untrue.37 As shown by the Advisors, in Mr. Hevert’s
testimony, he prepared no-less than five ROE analyses, of which only one supported an upper
range of 10.75%;38 and
WHEREAS, Advisors’ witness Watson conducted a two-step DCF analysis which sought
to estimate the implied ROE of utilities comparable to ENO as a proxy for ENO’s own appropriate
allowed-ROE, which itself cannot be directly measured;39 and
WHEREAS, Mr. Watson’s DCF analysis is also based on objective market data such as
dividend yields and professional analysts’ opinions as to growth factors.40 The results of witness
Watson’s two-step DCF ROE analysis establish, among proxy companies and unadjusted for risk
and flotation costs, a range of implied ROEs of 5.74% to 10.64% with a median implied ROE of
8.09%;41 and
WHEREAS, Advisors’ witness Proctor performed a CAPM analysis that identifies an
allowed-ROE of 7.57% (unadjusted for risk and flotation costs), which is less than Mr. Watson’s twostep DCF ROE analysis result;42 and

WHEREAS, however, the Advisors’ assert that as a DCF ROE analysis and a CAPM ROE
analysis are based on different financial concepts (i.e., DCF is based on dividend yields and growth
factors, while CAPM is based on market returns and correlations therewith), the relative
concurrence in results between these analyses has probative value for the Council in the instant
proceeding;43 and

Advisors’ Reply Brief at 4.
Ex. No. ADV-8 at 19-20, Table 2.
39
Ex. No. ADV-7 at 13:1-7 (HSPM).
40
Id. (HSPM).
41
Id. at 44:1-4 (HSPM).
42
Id. (HSPM).
43
Id. at 44:14-45:2 (HSPM).
37
38

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 WHEREAS, according to the Advisors, Mr. Watson has reviewed Mr. Proctor’s CAPM
study, which is based on accepted methodologies and data, and he agrees with Mr. Proctor’s
analysis and results;44 and
WHEREAS, Mr. Proctor discusses the ROE-related risk factors discussed by ENO
witness, Mr. Hevert, and recommends the Council allow a risk-related ROE upward adjustment in
this instant proceeding of 84 basis points;45 and
WHEREAS, the Advisors adjusted their ROE findings for additional business risk ENO
incurs largely as a result of its geographic location, its small size and its propensity to incur
significant storm damage;46 and
WHEREAS, according to the Advisors, Mr. Proctor’s one standard-deviation adjustment
methodology is objective and reflective of the variability of systemic risks among the Proxy
Companies. 47 The Advisors also state that they specifically evaluated and addressed ENO’s
business risk 48 and Mr. Proctor’s proposed 81 basis point adjustment was based on objective
analysis and is reasonable, while ENO’s arguments are general, subjective, and speculative;49 and
WHEREAS, the Advisors made an additional adjustment to their recommended ROE for
flotation costs which relate to incremental costs incurred from the issuance of common stock. 50
According to the Advisors, the costs are legitimately recoverable through utility rates either as a
cost of equity or an operating expense;51 and

44

Id. (HSPM).
Ex. No. ADV-10 at 61:3-63:6 (HSPM).
46
Id. at 61:3-10 (HSPM).
47
Advisors’ Initial Brief at 33.
48
Id.
49
Id.
50
Id. at 34.
51
Id.
45

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 WHEREAS, Mr. Watson presented the flotation cost-adjusted implied ROEs for the
proxy companies, the median of such values is 8.12%, or approximately 3 basis points greater
than the median of the non-flotation-adjusted proxy company implied ROEs.52 His two-step DCF
proxy company mean ROE analysis result of 8.09% plus these appropriate upward adjustments
for business risks and flotation costs yields an allowed-ROE of 8.93%;53 and
WHEREAS, the Advisors point out that the results of Mr. Proctor’s CAPM ROE analysis
are broadly consistent with those of Mr. Watson’s two-step DCF ROE analysis and the Advisors
recommend the Council take the results of Mr. Proctor’s CAPM ROE analysis into account in the
instant proceeding and adopt the Advisors’ ROE recommendation;54 and
WHEREAS, Intervenors, CCPUG and Air Products, also submitted testimony in this
proceeding that included ROE recommendations to the Council; and
WHEREAS, CCPUG provided two methods of analysis for estimating a fair ROR for
ENO, the DCF and CAPM analyses;55 and
WHEREAS, based on these independent analyses, CCPUG concluded that a reasonable
investor required ROE in the range of 8.70%-9.35% would be appropriate for ENO.56 Employing
these widely accepted financial methods for developing an ROE recommendation, CCPUG
recommends that the Council adopt an ROE of 9.35%, which is on the high end of CCPUG’s
range;57 and

52

Ex. No. ADV-7, Ex. No. BSW-4 (HSPM).
Advisors’ Initial Brief at 34.
54
Id.
55
Ex. No. CCPUG-3 at 15:15-24.
56
Id. at 30:3-6.
57
Id. at 30:6-7.
53

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 WHEREAS, with respect to evaluating and addressing ENO’s business risk for purposes
of making an ROE recommendation, CCPUG approached the issue of risk by acknowledging that
ENO’s business risk was considered by the credit rating agencies in their reports on ENO;58 and
WHEREAS, according to CCPUG, Moody's and S&P mentioned these risks in various
places in their reports which evaluated ENO’s credit profile, its risk associated with severe
weather, its small size, and the effect of the TCJA.59 CCPUG also observed that with regard to
customer diversity, the S&P report cited by CCPUG’s witness Mr. Baudino noted that ENO’s
customer mix was a credit strength, not a weakness;60 and
WHEREAS, CCPUG also argues that after assessing these risks, as well as credit
strengths possessed by ENO, S&P assigned credit ratings to ENO that were consistent with the
proxy group and with the electric utility industry in general and therefore CCPUG concluded that
no additional risk premium is necessary for ENO relative to the proxy group;61 and
WHEREAS, according to CCPUG, ENO’s proposed 10.75% ROE far exceeds the
average ROE awarded by regulators across the country in the last five years. 62 In fact, CCPUG
urges, according to ENO’s own data, its requested ROE of 10.75% is higher than all but one ROE
granted by a regulator to an electric and gas utility over the last five years;63 and
WHEREAS, Air Products also provided extensive ROE testimony in this case utilizing
several financial models to estimate ENO’s cost of common equity, including various forms of a
DCF analysis, a Risk Premium analysis and a CAPM analysis similar to the financial models used
by other ROE witnesses in the case;64 and

58

Ex. No. CCPUG-3 at 46:22-47:1-10.
Id.
60
Id.
61
Id.
62
CCPUG Initial Brief at 13.
63
Id. citing Ex. ENO-29 at 6:3, Chart 2.
64
Ex. No. AP-1 at 17:5-10.
59

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 WHEREAS, based on comprehensive studies utilizing multiple industry accepted
financial models, Air Products concluded that an ROE in the range of 9.0%-9.7% would be
appropriate for ENO.65 A recommended ROE for ENO of 9.35% was supported by Air Products
as a reasonable midpoint;66 and
WHEREAS, Air Products’ witness Christopher C. Walters undertook an extensive
analysis of the regulated utility industry’s access to capital, credit rating trends and outlooks, the
overall trend in authorized ROEs for electric utilities throughout the country, and the impact that
the Federal Reserve’s monetary policy actions have had on the cost of capital;67 and
WHEREAS, according to Air Products, Mr. Walters fully evaluated the market’s
perception of ENO’s investment risk and considered ENO’s proposed capital structure;68 and
WHEREAS, Mr. Walters then used several cost of equity estimation methods performed
on proxy group of publicly traded electric utility companies with comparable risk to ENO,
including (1) a constant growth DCF Model using the consensus of analysts growth rate
projections, (2) a constant growth rate DCF model using sustainable growth rate estimates, (3) a
multi-stage DCF model, (4) a Risk Premium model, and (5) a CAPM analysis;69 and
WHEREAS, according to Air Products, based on Mr. Walters’ extensive analysis, he
estimated that ENO’s current market cost of equity is in the range of 9.0% and 9.7%, with a midpoint estimate of 9.35%;70 and

65

Id. at 49:5-8.
Id.
67
Id. at 2:15-20.
68
Id. at 3:1-3 and 17:11-19:5.
69
Id. at 3:4-6 and 17:3-10.
70
Id. at 3:6-8.
66

20
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 WHEREAS, Mr. Walters presented Direct Testimony & Schedules demonstrating that
ROEs for electric and gas utilities have been reasonably stable well below 10.0% for about the
last six years;71 and
WHEREAS, Air Products states that during this period of declining ROEs, there has been
significant improvement realized in the electric utility industry’s overall credit quality and the
ability of regulated utilities to access significant amounts of capital to support record amounts of
capital investments over at least the last ten years;72 and
WHEREAS, as set forth by Air Products, Mr. Walters’ analysis and recommendation for
a 9.35% ROE for ENO took into consideration ENO’s specific investment risk and proposed
capital structure;73 and
WHEREAS, after performing several analyses utilizing multiple ROE financial models,
witness Walters recommended and overall ROE for ENO of 9.35%;74 and
WHEREAS, a 9.35% ROE is within the range of reasonable ROE recommendations made
in this docket by three parties that provided expert testimony on this issue, including the Advisors,
CCPUG, and Air Products; and
WHEREAS, ENO’s argues that the Federal Energy Regulatory Commission (“FERC”)
has changed the law as to which financial modeling should be used in setting an ROE.75 The
Advisors contend that the Company plainly mischaracterizes FERC’s statements on this issue.76
The Advisors also responded that FERC does not, as ENO suggests, require the use of four
financial models in setting an ROE that results in just and reasonable rates.77 FERC has simply

71

Id. at 4:4-10 and Figure 1.
Air Products’ Initial Brief at 13.
73
Id.
74
Id. at 15.
75
ENO Initial Brief at 38.
76
Advisors’ Reply Brief at 5.
77
Id.
72

21
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 proposed that more than one model be used as opposed to relying on only one model.78 The
Advisors maintain that FERC has not issued any rule or requirement, but simply stated in that
proceeding that it preferred to give consideration to the four financial models that were entered
into the record of that case.79 In fact, as noted by our Advisors, FERC has requested briefs from
the parties in that proceeding to consider its proposal as it relates to financial modeling that should
be used in evaluating and setting a ROE;80 and
WHEREAS, the Advisors have submitted testimony from two expert witnesses in this
case that do, in fact, include multiple sets of financial modeling data and results for the Council
to consider.81 Advisors’ witness Mr. Watson employed the DCF analysis and Mr. Proctor used
the Capital Asset Pricing Model CAPM analysis.82 The Advisors state that both models are well
accepted in the industry and they produce reliable results. Mr. Watson agreed with Mr. Proctor’s
CAPM modeling analyses and found that Mr. Proctor’s results were reasonable. 83 Mr. Watson
also recommends that the Council consider not only his DCF analysis, but also Mr. Proctor’s
analyses in making its decision to adopt a just and reasonable ROE. 84 Contrary to ENO’s
assertions, the Advisors utilized multiple models in conducting its ROE analyses and those
modeling results fully support the Advisors’ ROE recommendation;85 and
WHEREAS, four ROE experts in this case, using multiple methodologies widely
accepted in the utility industry, assert that ENO’s proposed ROE is poorly supported by ENO’s

Ass’n of Businesses Advocating Tariff Equity v. Midcontinent Indep. Sys. Operator, Inc., 165 FERC ¶ 61,118, at
34 (2018).
79
Advisors’ Reply Brief at 5.
80
Id.
81
Id.
82
Id.
83
Ex. No. ADV-7 at 45.
84
Id. at 49.
85
Advisors’ Reply Brief at 5-6.
78

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 own testimony.86 Mr. Hevert’s updated DCF analyses in his rebuttal testimony produced results
ranging from 8.34%-10.38% which clearly does not support his recommended 10.75% ROE.87
Similarly, Mr. Hevert’s revised CAPM ROE analyses presented in his rebuttal testimony
produced a substantially lower range of results, from 8.25%-11.34%, placing his recommended
10.75% near the top of his revised range of results;88 and
WHEREAS, the Council’s Advisors have shown that ENO’s updated analyses provide
further support for the Advisors’ and Intervenors’ arguments that the Company’s requested
10.75% ROE is unreasonable and not supported by the preponderance of evidence in the instant
docket;89 and
WHEREAS, the Council finds that the testimony provided by the Advisors’ ROE
witnesses, which was based on the utilization of more than one industry accepted financial method
is well supported and convincing evidence in this docket; and
WHEREAS, the Council finds that the 8.93% ROE recommendation made by the
Advisors is reasonable and supported by the Advisors analysis in this case; and
WHEREAS, the Council also finds that the ROE testimony provided by CCPUG and Air
Products in this case, which was also based on the utilization of multiple industry accepted
financial methods is similarly well supported and convincing evidence in this docket; and
WHEREAS, the Council finds that the 9.35% ROE recommendation made by CCPUG
and Air Products is also reasonable and supported by the analysis presented in this case; and

Advisors’ Initial Brief at 28; Air Products’ Initial Brief at 16; CCPUG Initial Brief at 32-35.
Ex. No. ENO-29 at 144:1.
88
Id.
89
Advisors’ Initial Brief at 28-29.
86
87

23
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 WHEREAS, the Council also acknowledges that the 9.35% ROE recommended by
CCPUG and Air Products in this case is also within the scope of ROEs supported by Advisors’
witness Watson’s analysis which resulted in a range of implied ROEs of 5.74% to 10.64%; and
WHEREAS, the Council agrees with the Advisors, CCPUG and Air Products that ENO’s
proposed ROE of 10.75% is not convincingly supported by ENO’s own testimony; and
WHEREAS, the Council agrees with the Advisors and Intervenors that ENO’s updated
analyses provide further support for the Advisors’ and Intervenors’ arguments that the Company’s
requested 10.75% ROE is unreasonably high and not supported by the preponderance of evidence
in the instant docket; and
WHEREAS, considering all of the testimony and evidence presented related to the
appropriate ROE for ENO in this proceeding, the Council finds that ENO’s proposed ROE of
10.75% should be rejected and an ROE of 9.35% is reasonable and should be adopted; and
EQUITY RATIO
WHEREAS, ENO has proposed that its actual equity ratio be employed for ratemaking
purposes in this proceeding.90 ENO witness Orlando Todd submitted testimony that ENO projects
its capital structure as of December 31, 2018 will consist of 52.2% common equity, with the rest
consisting of long-term debt;91 and
WHEREAS, the Company used this estimated 52.2% equity ratio to calculate its WACC
and revenue requirement in its cost of service studies in this proceeding;92 and

90

Id. at 35.
Ex. No. ENO-33 at 14:13-14.
92
Id.
91

24
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 WHEREAS, the Advisors submitted testimony contending that ENO’s proposed capital
structure, if adopted, would constitute inappropriate double leveraging;93 and
WHEREAS, according to the Advisors, a useful meaning of “double leverage” for the
purposes of the instant proceeding is the practice of maintaining a significantly higher common
equity ratio at the utility operating company level (i.e., ENO) than is maintained at the highest
corporate level ultimately owning the utility (i.e., Entergy Corp.);94 and
WHEREAS, because the return on a utility’s investment component of its revenue
requirement is customarily based on its WACC and the rate of the ROE component of WACC is
typically at a higher rate than those of the debt components (especially on a pre-tax basis), our
Advisors assert that a high common equity ratio tends to increase a utility’s WACC, and revenue
requirement;95 and
WHEREAS, our Advisors further argue that the effect of a utility that engages in double
leverage is as if it borrows money at the top corporate level and places that money into its utility
subsidiaries as common equity providing a potential return which is likely greater than its original
borrowed cost;96 and
WHEREAS, based on our Advisors’ analysis, ENO’s equity ratio is greater than those of
Entergy Corp. as well as the average of the other Entergy Operating Companies (“EOCs”);97 and
WHEREAS, according to testimony provided by our Advisors, ENO’s proposed equity
ratio of 52.2% is 18.1% higher than that of Entergy Corp. as of December 31, 2018, while the
average equity ratio of the other EOCs projected as of December 31, 2018, is only 15.5% higher

93

Ex. No. ADV-7 at 51:1-4 (HSPM).
Id. (HSPM).
95
Id. at 51:4-8 (HSPM).
96
Id. at 51:8-11 (HSPM).
97
Id. at 50:5-6 (HSPM).
94

25
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 than that of Entergy Corp.98 As such, the revenue requirement effect of ENO’s double leverage
on New Orleans ratepayers is more pronounced than that for the average ratepayer of the other
EOCs;99 and
WHEREAS, ENO claims that that the Advisors have misinterpreted the other Entergy
Operating Companies’ equity ratios and argues that the Advisors’ comparison of ENO’s proposed
equity ratio to the other Entergy Operating Companies “sheds no light on the issue;”100 and
WHEREAS, despite ENO’s claims to the contrary, the Advisors argue that comparing
ENO’s capital structure to that of the other EOCs is important for the Council’s consideration
because such a comparison serves as a guide for assessing the reasonableness of ENO’s capital
structure;101 and
WHEREAS, analyzing these comparisons, according to the Advisors, provides the
revenue requirement effect of ENO’s proposed capital structure as compared to that of the other
EOCs.102 In fact, employing ENO’s Period II External Models and changing ENO’s equity ratio
to be consistent with the non-ENO EOCs’ average equity ratio of 49.6% as opposed to ENO’s
proposed 52.2% yields a $1.5 million reduction in electric revenue and a $0.3 million reduction
in gas revenue;103 and
WHEREAS, considering the arguments set forth by the Advisors regarding double
leverage, the significance of ENO’s equity ratio being higher than that of the average of the other
EOCs and the impact of ENO’s proposed equity ratio on ratepayers, the Advisors recommend that

98

Id. at 53:1-3 (HSPM).
Id. at 53:3-5 (HSPM).
100
ENO’s Initial Brief at 60.
101
Advisors’ Initial Brief at 36.
102
Advisors’ Initial Brief at 36; Ex. No. ADV-7 at 52:20-53:5 (HSPM).
103
Advisors’ Initial Brief at 37; Ex. No. ADV-7 at 53:8-11 (HSPM).
99

26
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 the Council adopt an equity ratio of 50% in the instant proceeding for setting ENO’s electric and
gas rates;104 and
WHEREAS, for setting rates as part of any FRP evaluations the Council approves in this
case, the Advisors believe the Council should employ an equity ratio equal to the lesser of
(a) ENO’s then actual equity ratio properly excluding the effects of securitization bonds and cash,
and (b) 50%;105 and
WHEREAS, CCPUG asserts that ENO’s capital structure must include short-term debt,
because (a) it is abundantly available to ENO, (b) ENO routinely uses short-term debt for its
operations, and (c) it is the lower-cost option for capital as compared to long-term debt and ENO’s
requested 10.75% ROE;106 and
WHEREAS, according to CCPUG, ENO has available two sources of short-term debt.107
The first source is the internal Entergy Money Pool whereby Entergy operating utilities that have
a surplus of cash deposit it into the Money Pool and the Entergy operating utilities that need cash
borrow it from the Money Pool.108 The second source is an external Company-specific credit
facility of $25 million, which includes fronting commitments of up to $10 million for the issuance
of letters of credit against the borrowing capacity of the facility.109 CCPUG also claims that ENO
may borrow up to $150 million from the Entergy Money Pool, other internal short-term borrowing
arrangements, and external sources pursuant to FERC authorization;110 and

Advisors’ Initial Brief at 37; Ex. No. ADV-7 at 55:16-18.
Advisors’ Initial Brief at 37; Ex. No. ADV-7 at 55:16-56-1.
106
CCPUG Reply Brief at 21.
107
CCPUG Initial Brief at 95.
108
Id.
109
Id.
110
Id.
104
105

27
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 WHEREAS, Mr. Kollen explained that ENO should use some amount of short-term debt
in lieu of long-term debt and common equity to reduce its cost of capital and its revenue
requirements;111 and
WHEREAS, CCPUG witness Mr. Kollen testified it is not reasonable for ENO to exclude
short-term debt from the capital structure and cost of capital, especially since short-term debt is
available to ENO at a fraction of the cost of long-term debt and common equity;112 and
WHEREAS, ENO relies heavily on a Louisiana Supreme Court decision to support its
unreasonably high capital structure proposal;113 and
WHEREAS, according to the Advisors, ENO claims that the Court in South Central Bell
held very narrowly that the utility “‘is entitled to have its rates fixed on the basis of its actual cost
of capital under its existing capital structure’” absent a finding “‘that the actual capital structure
of the utility resulted from unreasonable or imprudent investments;’”114 and
WHEREAS, the Company also claims that the Advisors have “not pointed to a single
instance that the Company made an unreasonable investment or financing decision.”115 However,
ENO’s strict interpretation of the Court’s ruling on this issue is erroneous. South Central Bell
plainly states that if the regulator finds that the utility’s proposed capital structure is unreasonable,
it may adopt a reasonable alternative;116 and

111

CCPUG Initial Brief at 96.
Id. at 96-97, citing Ex. CCPUG-1 at 39:1-5.
113
Ex. No. ENO-3 at 24:5-6; Ex. No. ENO-4 at 15:17-19; citing S. Cent. Bell Tel Co. v. Louisiana Pub. Serv. Comm’n,
594 So. 2d 357.
114
Ex. No. ENO-4 at 15:19-16-1; citing S. Cent. Bell Tel Co. v. Louisiana Pub. Serv. Comm’n, 594 So. 2d 357.
115
Id. at 16:1-2.
116
S. Cent. Bell Tel. Co. v. Louisiana Pub. Serv. Comm’n, 594 So. 2d at 363.
112

28
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 WHEREAS, specifically, the Court stated, “we conclude … that the Commission must
find a utility’s capital structure imprudent or unreasonable before disregarding it in ratemaking;117
and
WHEREAS, the Advisors argue that the unreasonableness is, thus, not limited to
investments made by the utility.118 The unreasonableness that the Advisors explain primarily
from, among other reasons, the effect of double leverage that exists as a result of Entergy
Corporation having a significantly lower equity ratio than that of its subsidiary, ENO;119 and
WHEREAS, CCPUG also maintains that ENO’s proposed capital structure is
unreasonable because it fails to include short-term debt;120 and
WHEREAS, a later Louisiana Supreme Court case, cited by the Advisors, supports the
Advisors’ and CCPUG’s argument regarding the regulator’s ability to set aside the utility’s
unreasonable capital structure in favor of a more equitable alternative;121 and
WHEREAS, in the Entergy Gulf States case, the utility used the net proceeds of debt to
determine the ratio of debt to equity capital in its capital structure.122 The Commission, however,
adjusted the Company’s filing by reducing its average weighted cost of capital to reflect the gross
proceeds of debt in the company’s capital structure. 123 The sole capital structure problem
presented to the Court was whether the Commission acted arbitrarily or capriciously by including
the gross proceeds of debt, rather than the net proceeds of debt, in the Company’s capital

117

Id.
Advisors’ Initial Brief at 38.
119
Id.
120
CCPUG Reply Brief at 21.
121
Entergy Gulf States, Inc. v. Louisiana Pub. Serv. Comm’n, 730 So. 2d 890 (La. 1999).
122
Id. at 915-16.
123
Id.
118

29
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 structure.124 In affirming the regulator’s authority to adopt a different capital structure than the
one proposed by the utility, the Court stated:

The right of commissions to consider [capital structure] in setting rates cannot be
questioned, since a commission has an obligation to protect the consumer from
excessive wages, excessive pension provisions, excessive prices for purchased
materials and supplies, and other such things, including excessive costs of capital125
and
WHEREAS, the Court also clearly found, in affirming the regulator’s adjustment to the
utility’s proposed capital structure, that the utility had not demonstrated that the Commission had
set unjust or unreasonable rates. 126 Orders of utility regulators in the State of Louisiana are
“entitled to great weight” and “they should not be overturned absent a showing of arbitrariness,
capriciousness, or abuse of authority by the Commission.”127 Courts should also “be reluctant to
substitute their own views for those of the expert body charged with the legislative function of
rate-making;”128 and
WHEREAS, the Advisors urge the Council to note that ENO routinely recommends
utilizing a hypothetical capital structure in requesting rate recovery of costs incurred by the
Company.129 For example, the Company acknowledged in this proceeding that in Council Docket
No. UD-15-01, ENO’s own witness recommended a hypothetical capital structure of 50% be used
for ratemaking purposes for the recovery of costs associated with the acquisition of Union Power
Block #1.130 According to the Advisors, ENO also employed an “Assumed 50% Common Equity”
even though ENO’s actual equity ratio was not 50% in Council Docket No. UD-17-02 related to

124

Id.
Id. at 917, citing Paul J. Garfield & Wallace F. Lovejoy, Public Utility Economics at 130 (1964).
126
Id.
127
Id. at 897.
128
Id.
129
Advisors’ Initial Brief at 39.
130
City Council Hearing Transcript, 120:5-9 (June 20, 2019).
125

30
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 the Company’s Gas Infrastructure Rebuild Program.131 The Advisors also point out that, in these
instances, when recommended by the Company, a 50% equity ratio was not only reasonable but
specifically proposed by ENO is its requests for cost recovery;132 and
WHEREAS, the Council agrees with the Advisors and CCPUG that ENO’s proposed
equity ratio is unreasonable; and
WHEREAS, the Council also agrees that an unreasonably high equity ratio would
constitute an inappropriate amount of double leveraging, result in an unreasonably higher equity
ratio than those of Entergy Corp. as well as an equity ratio higher than the average of the other
EOCs; and
WHEREAS, the Council also agrees with the Advisors and CCPUG that Louisiana Law
allows a regulator to set aside the utility’s unreasonable capital structure in favor of a more
equitable alternative; and
WHEREAS, the Council finds that the inclusion of short-term debt in the calculation of
ENO’s allowed ROR (i.e., WACC) is contrary to established Council ratemaking practices and is
not supported by the preponderance of evidence in the instant proceeding; and
WHEREAS, as shown by the Advisors and CCPUG in sworn testimony and supporting
analyses provided in this proceeding, ENO’s proposed capital structure is unreasonably high and
the Council rejects ENO’s proposal in favor of a more reasonable equity ratio of the lesser of 50%
or ENO’s actual equity ratio for the purposes of this instant proceeding and for the FRP evaluations
ordered in this resolution; and

131
132

Ex. No. ADV-7 at 54:18-55:3 (HSPM).
Advisors’ Initial Brief at 39.

31
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 DEPRECIATION RATES
WHEREAS, ENO’s witness Donald J. Clayton sponsored new depreciation rates based
on a study conducted by Tangibl, LLC, which was carefully reviewed by the Council’s
Advisors.133 The study states that it employs accepted depreciation study methodologies to create
what is commonly referred to as Iowa Curve factors taking into account survivor curves, expected
retirement dates, and salvage factors.134 Mr. Clayton reports that ENO’s proposed depreciation
rates would increase ENO’s depreciation expense by $2.5 million and $0.1 million for electric and
gas respectively as compared to retaining ENO’s currently approved depreciation rates; 135 and
WHEREAS, the Advisors reviewed Mr. Clayton’s testimony and indicated that ENO’s
proposed depreciation rates are based on accepted analytical methodologies and represent an
incremental change to depreciation rates that ENO reports as having been in effect since 1980 and
2009 for electric and gas respectively.136 Further, as depreciation represents recovery of ENO’s
investments in plant, ENO’s requested overall increase in depreciation rates serves to slightly
hasten the decline in ENO’s appropriate dollar return on rate base. 137

ENO’s proposed

depreciation rates also appropriately provide for removing stranded costs (i.e., related to a general
plant reserve deficiency) from rate base over a 10-year period. 138 Accordingly, the Advisors
recommended the Council adopt ENO’s proposed new depreciation rates;139 and
WHEREAS, CCPUG argues that ENO’s proposed service lives for Union Power Station,
Power Block 1 (“UPS”) and New Orleans Power Station (“NOPS”) are unsupported and

133

Ex. No. ADV-7 at 60:3-4 (HSPM).
Id. at 60:4-6 (HSPM).
135
Ex. No. ENO-35 at 16, Comparison table.
136
Ex. No. ADV-7 at 61:7-17 (HSPM).
137
Id. (HSPM).
138
Id. (HSPM).
139
Id. (HSPM).
134

32
US_Active\113477234\V-1

 unreasonably short.140 In doing to, according to CCPUG, ENO seeks to accelerate the recovery of
depreciation on these plants and to unnecessarily inflate its revenue requirement, respectively.141
CCPUG urges the Council to reject ENO’s unrealistically short service lives and the related
depreciation expense and instead use a 40-year service life for UPS, and change the first-year
revenue requirement to reflect a 50-year service life for NOPS (rather than a 30-year life);142 and
WHEREAS, CCUPG witness Mr. Kollen examined publicly-available information from
the Energy Information Administration which showed that similar combined cycle units were in
service for 40 to 50 years before their retirements;143 and
WHEREAS, ENO witness Mr. Clayton admitted that determining the service life of a
generating unit for depreciation purposes and estimating salvage value is not an exact science.144
Also according to Mr. Clayton, the retirement date of a plant is an important factor in determining
its service life;145 and
WHEREAS, the decision whether to retire a plant is driven by multiple factors according
to ENO, such as repair costs, location of the plant, and environmental issues.146 However, ENO
provided the retirement date for UPS to Mr. Clayton, but did not provide him with any studies,
analyses, or empirical data supporting that decision;147 and
WHEREAS, according to CCPUG, Mr. Clayton attempted to dispute Mr. Kollen’s use of
similar plants to establish the service life for UPS by claiming that, because UPS (a combined cycle

140

CCPUG Initial Brief at 64.
Id.
142
Id.
143
Ex. No. CCPUG-1 at 29:7-30:10.
144
City Council Hearing Transcript, 138:23-139:5 (June 18, 2019).
145
Id., 140:3-11.
146
Id., 140:3-11.
147
Id., 141:20-142:7.
141

33
US_Active\113477234\V-1

 gas plant) was constructed after 2000, that the combined cycle gas plants Mr. Kollen referenced, which
were constructed prior to 2000, were not comparable;148 and
WHEREAS, however, CCPUG points out that Mr. Clayton offers no proof whatsoever that
UPS’ service life will, most likely, be shorter than a pre-2000 combined cycle plant;149 and

WHEREAS, according to testimony provided by ENO, a major component replacement
can extend the service life of a generating unit.150 Mr. Breedlove opined that the combustion
turbine rotors are a “major component” of UPS and have an estimated service life of roughly 19
years. 151 However, Mr. Breedlove did not recommend a 19-year service life for UPS; he
recommended a 30-year life.152 CCPUG asserts that to reach a 30-year life, UPS will most likely
have to replace its combustion turbine rotors. 153 Although the service life of a plant is not
determined by any one component, in CCPUG’s view, the combustion turbine rotors are a major
component that can greatly extend the life of the plant;154 and
WHEREAS, Mr. Kollen recommends the use of a 40-year service life for UPS and
estimates that the financial effect his recommendation would be a $5.029 million reduction in
ENO’s electric base revenue requirement;155 and
WHEREAS, in addition, CCPUG claims that ENO has no experience with retirements or
net salvage value for UPS means that its actual experience is 0% net salvage156 not negative 8%
as ENO proposes. Mr. Kollen calculated that the effect of employing a 0% net salvage value for

148

Id., 148:5-149:5.
CCPUG Initial Brief at 66.
150
Ex. ENO-48 at 5:4-12.
151
Id. at 5:1-18; see also, City Council Hearing Transcript, 71:1-72:15 (June 19, 2019).
152
CCPUG Initial Brief at 66.
153
Id.
154
Id.
155
Ex. No. CCPUG-1 at 30:17-18.
156
Id. at 31:7-15.
149

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 UPS for depreciation purposes would lead to a reduction of $0.628 million in the electric base
revenue requirement;157 and
WHEREAS, with respect to NOPS, Mr. Kollen investigated publicly-available
information on retirements of combustion turbine plants, like NOPS, and found that similar units
have been in operation for nearly 50 years or more;158 and
WHEREAS, CCPUG asserts that the utility is made whole over time, because it will
collect all of its depreciation, including consideration for salvage value; thus, the issue is whether
ENO collects these costs over 30 years or 40 years or 50 years;159 and
WHEREAS, Mr. Kollen recommends that a 9.35% ROE be used in the E-FRP, the firstyear revenue requirement be reduced to reflect a 50-year service life, and ENO be ordered to
reduce the revenue requirement for NOPS each year to reflect an additional year of depreciation
and deferred income tax expense;160 and
WHEREAS, Mr. Kollen then calculated the effect of his recommendations and concludes
the first-year revenue requirement for NOPS should be reduced by $4.073 million;161 and
WHEREAS, the Council believes the CCPUG has made a compelling argument for
extending the service lives for UPS and NOPS for the purposes of depreciation; and
WHEREAS, CCPUG has provided significant evidence in the record establishing that the
service lives for these particular types of generating technology is considerably longer than ENO
has proposed for purposes of calculating depreciation rates; and

157

Id. at 32:22-23.
Id. at 47:1-19.
159
CCPUG Initial Brief at 68.
160
Ex. No. CCPUG-1 at 48:6-13.
161
Id. at 48:15-20.
158

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 WHEREAS, the Council believes that ENO’s ratepayers will benefit from lower rates if
the utility utilizes longer service life estimates for calculating depreciation rates; and
WHEREAS, the Council finds that CCPUG’s recommended 40-year service life for UPS
and 50-year service life for NOPS shall be used by ENO in calculating depreciation rates in this
proceeding; and
TAX ISSUES
(1)

FIN 48 ADIT Liabilities

WHEREAS, the Financial Accounting Standards Board’s Interpretation No. 48162 (“FIN
48”) provides an interpretation of FAS No. 109 regarding the accounting for uncertainty in income
taxes recognized in financial statements;163 and
WHEREAS, in applying FIN 48, a determination is made by the taxpayer for specific
transactions as to whether it is more likely than not that a tax position will be sustained upon
examination, including resolution of appeals or litigation processes, based on the technical merits
of the position. Then the tax position is measured at the largest amount of benefit that is greater
than 50% likely to be realized upon ultimate settlement. This amount is recognized as an
Accumulated Deferred Income Tax (“ADIT”) liability for financial reporting purposes;164 and
WHEREAS, ENO, through complying with normalization rules, records Deferred Income
Tax (“DIT”) expense that is part of ENO’s cost of service and is recoverable in utility rates; 165 and
WHEREAS, ENO has proposed to remove from its electric and gas rate bases, the portion
of various ADIT liabilities that it states are unlikely to produce cost-free capital due to the

162

Financial Accounting Series No. 281-B, June 2006, FASB Interpretation No. 48 of the FASB of the Financial
Accounting Foundation.
163
Advisors’ Initial Brief at 40.
164
Id. at 40-41.
165
Id. at 42.

36
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 aggressive tax positions taken by the Company in its filings with federal and state taxing authorities
(FIN 48 ADIT),166 with the specific proposed amounts by account to be so excluded;167 and
WHEREAS, the Advisors disagree with ENO’s proposed ratemaking treatment of FIN 48
ADIT liabilities. The Advisors evaluated the FIN 48 ratemaking issues in this proceeding in a two
pronged approach: (1) how is the financial risk shared between ratepayers and shareholders with
respect to the uncertainty of the income tax position taken by ENO; and (2) making the correct
adjustment required for ratemaking purposes. With respect to issue of financial risk, the Advisors
disagree with ENO’s adjustment to eliminate FIN 48 ADIT liability balances from rate base for its
electric and gas operations;168 and
WHEREAS, the Advisors argue that ENO’s recording of DIT expense and including it in
its cost of service provides ENO a cost-free loan from the ratepayers which requires that the related
FIN 48 ADIT liability also be included in rate base;169 and
WHEREAS, ENO argues that its aggressive tax positions underlying the FIN 48 ADIT
essentially have no effect on the level of income tax expense included in ENO’s revenue
requirement in its Period II Electric and Gas Cost of Service Studies, and a result, when considering
income tax expense, a utility’s customers are indifferent as to whether a utility uses aggressive tax
positions on its tax return;170 and
WHEREAS, ENO argues that FIN 48 ADIT is not cost-free capital in that ENO accrues
interest expense on its aggressive tax positions, and that interest expense is borne by ENO and not
recovered by ENO from customers in rates;171 and

166

Id. at 41.
Ex. No. ENO-1 at 71, Table 3 (HSPM).
168
Advisors’ Initial Brief at 41-42.
169
Id. at 42.
170
ENO Post-Hearing Brief at 147.
171
Id.
167

37
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 WHEREAS, the Advisors support ENO’s recovery of prudently incurred interest expense
attributed to ENO paying interest for tax underpayments to the federal government related to
prudent FIN 48 positions it takes;172 and
WHEREAS, the CCPUG recommends that that the Council authorize ENO to record a
regulatory asset and seek recovery in a future ratemaking proceeding for the interest paid to the
IRS related to FIN 48 ADIT calculated from the date when rates are reset in this proceeding;173
and
WHEREAS, the CCPUG agrees with the Advisors that ENO’s proposed treatment of FIN
48 amounts to a cost-free loan from the ratepayers to ENO and that in this way, ENO pockets the
carrying charge value on the savings that were funded by ratepayers. The CCPUG argues that the
Council should subtract the FIN 48 ADIT amounts from rate base;174 and
WHEREAS, the Advisors make certain recommendations regarding the recoverability of
DIT in the event the Council approves ENO’s proposal to exclude FIN 48 ADIT from rate base;
and
WHEREAS, the Council agrees with ENO that its aggressive tax positions underlying FIN
48 ADIT have no effect on its income tax expense as presented in its Period II electric and gas cost
of service studies in the instant proceeding; and
WHEREAS, ENO’s argument that its aggressive tax positions underlying FIN 48 ADIT
having no effect on income tax expense is supportive of its proposal to exclude FIN 48 ADIT from
its rate base is unpersuasive, and the Council agrees with the Advisors and the CCPUG that such

172

Ex. No. ADV-13 at 63.
Ex. No. CCPUG-1 at 26.
174
CCPUG Post-Hearing Brief at 38.
173

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 proposed treatment provides ENO a cost-free loan from the ratepayers in which ENO pockets the
carrying charge value of savings funded by ratepayers; and
WHEREAS, the Council finds that FIN 48 ADIT liabilities should be included in ENO’s
rate base; and
WHEREAS, any discussion as to the appropriate ratemaking treatment of DIT in the event
FIN 48 ADIT liabilities are excluded from ENO’s rate base is moot; and
WHEREAS, the Council finds that the FIN 48 ADIT liabilities ENO has proposed to
exclude from its gas and electric rate bases as part of its electric and gas Period II cost of service
studies in the Revised Application175 should be included in ENO’s gas and electric rate bases; and
WHEREAS, the Council agrees that prudently undertaken aggressive tax positions may
involve prudently incurred related costs such as interest accruals or payments related to the period
starting with the effective date of rates established herein; and
WHEREAS, the Council generally agrees that the CCPUG’s recommended treatment of
prudently incurred interest payments related to FIN 48 ADIT through a regulatory asset is
reasonable, although the Council notes that it would authorize the creation of any such regulatory
asset; and
WHEREAS, in future retail rate actions before the Council, ENO may propose for Council
consideration a ratemaking mechanism for the recovery of prudently incurred costs related to FIN
48 ADIT liabilities that are included in ENO’s rate base, such as interest accrued or paid, and
related to the period starting with the effective date of rates established herein; and

175

Ex. No. ENO-1 at 71, Table 3 (HSPM).

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 (2)

NOLCF ADIT Assets

WHEREAS, in any given year, when a company has more income tax deductions than
taxable income, the excess of the income tax deductions over taxable income is called a net
operating loss (“NOL”). This NOL represents a future income tax benefit that ENO may use, and
is referred to as a net operating loss carry forward (“NOLCF”) and recorded as an ADIT asset;176
and
WHEREAS, ENO proposes to include NOLCF ADIT asset balances attributable to
accelerated tax depreciation in its rate base, citing two Private Letter Rulings (“PLR”) that ENO
argues explain the income tax normalization rules that require the inclusion in its rate base of the
NOLCF ADIT asset balance attributable to accelerated tax depreciation;177 and
WHEREAS, ENO argues that the two PLRs it cites explain that the NOLCF ADIT asset
balance must be included in ENO’s rate base to offset the credit ADIT by the amount for which
no cost-free capital was received, otherwise a normalization violation of the IRS’s income tax rules
could cause the IRS to prohibit ENO from using accelerated tax depreciation on its income tax
return;178 and
WHEREAS, through a response to discovery propounded upon ENO by the Advisors in
the instant proceeding, ENO revised downward the amount of NOLCF ADIT it proposes to include
in its electric and gas rate bases in the instant proceeding;179 and
WHEREAS, the Advisors argue that the Council should not rely on the conclusions drawn
in the two PLRs cited by ENO because it is impossible to compare the facts, as presented by the
taxpayers in those cases, to this case as presented by ENO and note that there is no indication that

Advisors’ Initial Brief at 45.
Id. at 46.
178
Id.
179
ENO Post-Hearing Brief at 169; ENO Post-Hearing Reply Brief at 120.
176
177

40
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 the taxpayers that requested the PLRs stated that deferred income tax expense was reflected in
their rates in prior periods, and without the benefit of this critical information, the Council is unable
to rely on these PLRs as a basis for approving ENO’s proposed ratemaking treatment of NOLCF
ADIT asset balances;180 and
WHEREAS, the Advisors also argue that, even if ENO’s cited PLRs may be relied upon
by the Council in the instant proceeding, ENO’s NOLCF ADIT asset is not attributable to
accelerated depreciation because the NOL cannot be tied to the excess depreciation over straightline depreciation;181 and
WHEREAS, the Advisors further argue that ENO’s total income tax expense, for financial
accounting purposes, includes a current provision payable to the government based on income tax
law and a deferred provision based on financial accounting standards, and as such ENO was
allowed recovery of all tax expenses, current and deferred, which constitutes taxable revenue;182
and
WHEREAS, the Advisors argue that due to ENO’s allowed recovery of all tax expenses,
the NOL carried forward during the previous periods was less than it otherwise would have been
by an amount equal to the deferred income taxes which were not paid to the government but were
collected from ratepayers;183 and
WHEREAS, the Advisors state that none of ENO’s NOLCF ADIT assets are directly
“attributable” to income tax timing differences, or the attributable balance of such is zero, and they

Advisors’ Initial Brief at 46-47.
Id. at 48.
182
Id.
183
Id. at 48-49.
180
181

41
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 recommend the Council deny ENO’s proposal to add NOLCF ADIT asset balances to its rate
bases;184 and
WHEREAS, the Advisors discussed and made recommendations as to Council regulatory
treatment of DIT should the Council allow ENO to include NOLCF ADIT asset balances in its rate
bases;185 and
WHEREAS, the Council finds persuasive the Advisors’ argument that ENO has been
allowed recovery of all of its book tax expenses, including DIT related to accelerated depreciation,
and as such, the NOLCF ADIT asset balance attributable to accelerated depreciation is zero; and
WHEREAS, as the Council herein finds that any NOLCF ADIT asset amount properly
includable in ENO’s rate bases in the instant proceeding is zero, further consideration as to the
probative value of ENO’s two cited PLRs is not necessary at this time and any discussion of
alternate regulatory treatment is moot; and
(3)

Rider SSCO ADIT

WHEREAS, the Advisors recommend the Council direct ENO to employ its then current
WACC when setting Rider SSCO’s rates,186 a recommendation that is not opposed by ENO187 or
any party to the proceeding; and
WHEREAS, the Council finds that ENO should employ its then current WACC, reflective
of the provisions for a cap on ENO’s equity ratio therein as ordered herein, when periodically
setting Rider SSCO’s rate; and

184

Id. at 49.
Id. at 46.
186
Id. at 149.
187
ENO Post-Hearing Reply Brief at 115.
185

42
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 WHEREAS, as part of ENO’s rebuttal testimony, ENO stated that in its Revised
Application, it failed to make the entry to remove the balance of ADIT associated with Rider SSCO
from the rate base in its cost of service studies,188 as noted in ENO’s Post Hearing Brief;189 and
WHEREAS, at Hearing, ENO offered a dollar revenue requirement effect of its stated
failure to remove ADIT associated with Rider SSCO from its rate base,190 as noted in ENO’s Post
Hearing Brief;191 and
WHEREAS, per the procedural schedule in the instant proceeding the Council-authorized
period of discovery had expired prior to the Hearing; and
WHEREAS, the Council approved a procedural schedule in the instant proceeding
calculated to afford parties to carefully inspect, validate, and rebut as necessary the proposals and
claims of other parties; and
WHEREAS, due to the timing of ENO’s statements and disclosures, parties to the instant
proceeding were not afforded the opportunity to inspect, validate, propound discovery related to,
or rebut ENO’s claim as to the dollar amount of the revenue requirement effect of any such failure;
and
WHEREAS, the Council finds that evidence in the Administrative Record is insufficient
to support setting rates reflective of ENO’s stated dollar revenue requirement effect192 related to
ENO’s stated failure to remove ADIT related to Rider SSCO from its rate base; and

188

Ex. No. ENO-3 at 42-43.
ENO Post-Hearing Brief at 170.
190
City Council Hearing Transcript at 178-179 (June 17, 2019).
191
ENO Post-Hearing Brief at 170.
192
City Council Hearing Transcript at 178-179 (June 17, 2019).
189

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 (4)

ADIT Related to Stranded Plant

WHEREAS, as part of the AMI deployment ENO must retire certain related existing plant,
such as meters, prior to its full recovery through depreciation (“Stranded Plant”);193 and
WHEREAS, the retirement of this Stranded Plant is associated with ENO’s per-book
recording of ADIT liabilities; and
WHEREAS, the economic benefit to ENO of Stranded Plant ADIT in the form of costfree capital is undisputed;194 and
WHEREAS, in its Revised Application, ENO removed ADIT related to Stranded Plant
from rate base;195 and
WHEREAS, the Advisors argue that ENO’s rates should reflect the economic benefit it
enjoys due to cost-free capital, such as ADIT related to Stranded Plant;196 and
WHEREAS, ENO argues that allowing ADIT related to Stranded Plant in its rate base
could constitute a “potential violation” of IRS normalization rules;197 and
WHEREAS, out of an abundance of caution regarding ENO’s argument of a “potential
violation” of IRS rules, the Advisors recommend the Council recognize the benefit to ENO of
cost-free capital and direct ENO to create regulatory liabilities;198 and
WHEREAS, ENO argues that the Council’s creating a regulatory liability to recognize
ENO’s economic benefit related to cost-free capital amounts to “changing the name of the reserve
or the book account of the reserve,” and does not negate the “potential” IRS normalization rules
violation;199 and
Advisors’ Initial Brief at 147.
Id. at 148.
195
Id.
196
Id.
197
Id.
198
Id.
199
ENO Post-Hearing Reply Brief at 74.
193
194

44
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 WHEREAS, ENO states that the Council should reject the Advisors’ recommendation to
create a regulatory liability as it would result in a normalization violation and harm customers; 200
and
WHEREAS, the Council finds nothing in the record demonstrating that the Advisors are
recommending the Council “change the name” or “book account” of any reserve; and
WHEREAS, the Council agrees that the Advisors’ recommendation to create a regulatory
liability is to reflect the undisputed economic benefit to ENO of cost-free capital through Stranded
Plant ADIT; and
WHEREAS, the Council notes its authority to set rates based in part on allowing ENO the
reasonable opportunity to recover its prudently incurred costs; and
WHEREAS, the Council notes its authority to create regulatory liabilities as part of its
ratemaking authority; and
WHEREAS, the Council finds that ENO should record a regulatory liability reflective of
the economic benefit of cost-free capital through Stranded Plant ADIT, with such regulatory
liability being a component of ENO’s electric and gas rate bases; and
RESTRICTED STOCK INCENTIVE PLAN
WHEREAS, the Advisors audited ENO’s affiliate transactions, and for the most part,
found that ENO had properly treated its Billing Adjustments related thereto, with one exception.201
Based on the Advisors’ review of ENO’s affiliated transactions during the test-year period, the
Advisors recommend that the cost of ENO’s Restricted Stock Incentive Plan (“Plan”) should not
be recovered in rates. 202 The Advisors assert that this recommendation would reduce ENO’s

200

Id.
Ex. No. ADV-17 at 3:9-7:14.
202
Ex. No. ADV-17 at 3:4-6.
201

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 revenue requirement related to its electric operations by $648,314 and the revenue requirement
related to its gas operations by $145,211;203 and
WHEREAS, ENO argues that this adjustment is unwarranted because the Advisors have
not demonstrated that ENO’s compensation plans are unreasonable.204 However, the Advisors
argue that incentive compensation plans and stock options may only be recovered in rates to the
extent that the Company demonstrates that such plans benefit ratepayers.205 Whether or not the
Plan is reasonable, it is tied to the long-term performance of Entergy Corporation common stock,
therefore the benefit of the Plan accrues solely to Entergy shareholders, and not to ratepayers, and
therefore the costs thereof should not be recovered through rates.206 The Advisors also point out
that other jurisdictions have disallowed these costs from being recovered from customers for the
same reasons that Advisors’ witness Mr. Ferris cites in his testimony;207 and
WHEREAS, the Council agrees with the Advisors that ENO has failed to provide support
for its position regarding the inclusion of the Plan’s costs in rates. Additionally, simply because a
cost may be legitimate and prudent does not necessarily require those costs to be borne by
ratepayers. The Council also notes that ENO incurs costs routinely that may be legitimate and
prudent, but not recoverable from ratepayers. The Council further agrees with the Advisors that
ENO has not provided any rational justification for recovering the costs of ENO’s Restricted Stock
Incentive Plan in rates. Accordingly, the Council finds that the Company has failed to meet its
burden of showing that the Restricted Stock Incentive Plan benefits ratepayers and therefore,
rejects ENO’s proposal to include these costs in rates; and
Advisors’ Initial Brief at 49, citing Ex. No. ADV-17 at 3:6-8.
ENO Initial Brief at 163; Ex. No. ENO-3 at 50:14-17.
205
Ex. No. ADV-18 at 4:5-7.
206
Id. at 4:12-16.
207
Ex. No. ADV-17 at 9:20-10:2 citing LPSC Order No. U-20925 (RRF 2004) and attached Recommendation on
Contested Proposed Stipulated
Settlement at 16.
203
204

46
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 ENO’S PREPAID PENSION ASSET ADJUSTMENT
WHEREAS, ENO included an adjustment for its Prepaid Pension Asset as part of its rate
base;208 and
WHEREAS, the Advisors argue that ENO’s inclusion of the Prepaid Pension Asset in rate
base is conceptually correct;209 and
WHEREAS, the Advisors took exception to ENO’s calculation of the asset included in
rate base because it is based on a forecasted balance for the year-end December 31, 2018.210
Instead of using forecasted calculations, the Advisors recommend that the Pension Asset balance
be based on the actual December 31, 2018 balances211 when provided by ENO, which would more
accurately reflect the market value of the Asset;212 and
WHEREAS, ENO argued that the Advisors’ reasoning was incorrect because the Prepaid
Pension Asset’s growth is not driven by the market value of the pension trust fund assets but by
ENO’s contributions to the pension trust fund;213 and
WHEREAS, upon receipt of ENO’s responses to the Advisors’ discovery requests
regarding ENO’s Prepaid Pension Asset adjustment, the Advisors found that ENO’s actual funded
status of its pension funds at December 31, 2018 was significantly less than the amount forecasted
by Entergy’s actuaries, AON Hewitt.214 Also, ENO’s actual balance for its benefit obligations
regulatory asset at December 31, 2018 was significantly larger than the amount forecasted by AON

ENO’s Initial Brief at 150.
Ex. ADV-9 at 63:9-10.
210
Id. at 63:10-11.
211
Id. at 63:11-14.
212
The Advisors issued two discovery requests to ENO seeking information to determine the actual adjusted balance
for the Pension Asset as of December 31, 2018. The two requests, CNO 12-2 and CNO 12-3 were outstanding at the
time the Advisors were required to file direct testimony.
213
ENO Initial Brief at 150.
214
Ex. ADV-9 at 65:13-19.
208
209

47
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 Hewitt. 215 Further, AON Hewitt’s overestimated funded status for ENO’s pension funds and
underestimated balance for ENO’s benefit obligations regulatory asset at December 31, 2018,
respectively, offset one another.216 Therefore, the Advisors determined that as a result of this
netting process, ENO’s Pension Asset remains unaffected from differences between estimated and
actual net gains and losses;217 and
WHEREAS, in his Surrebuttal Testimony, Advisors’ witness Mr. Proctor proposed that
his recommendation for the Prepaid Pension Asset in rate base is also appropriate because it is
supported by the lower historical five-year average year-end value of the Asset due to the growth
of the Prepaid Pension Asset from recent financial market conditions and the amount of ENO’s
contributions;218 and
WHEREAS, ENO responded that the Prepaid Pension Asset’s growth is not driven by the
market value of the pension trust fund assets but by ENO’s contributions to the pension trust fund
in excess of pension expense. 219 Contributions are tendered according to a plan provided by
ENO’s actuary setting forth the expected amount of the contributions and their timing.220 Pension
expense is generally determined at the beginning of the year by ENO’s actuary. 221 ENO asserts
that its discovery responses related to this issue show that the market value of the pension trust
fund assets has no effect on the quantification of the Prepaid Pension Asset;222 and
WHEREAS, the Council has considered the parties’ positions related to ENO’s Prepaid
Pension Asset adjustment and concludes that the Asset should be included in rate base; and

215

Id.
Id.
217
Ex. ADV-9 at 66:14-16.
218
Id. at 69:17-20.
219
ENO Initial Brief at 151
220
Id.
221
Id.
222
Id.
216

48
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 WHEREAS, the Council also believes that ENO has reasonably demonstrated that the
market value of the pension trust fund assets does not have an effect on the quantification of the
of the Prepaid Pension Asset for the purposes of inclusion of the Asset in base rates; and
WHEREAS, ENO’s Prepaid Pension Asset adjustment should be included in rate base and
quantified as proposed by the Company in its Revised Application; and
GAS INFRASTRUCTURE REPLACEMENT PROGRAM
WHEREAS, on January 26, 2017, in Docket No. UD-07-02, the Council adopted
Resolution R-17-38 which authorized ENO “to proceed with the replacement of gas infrastructure
. . . at a rate of approximately 25 miles per year and approximately $12.5 million in capital
investment per year” until the resolution of the instant rate case docket;223 and
WHEREAS, ENO proposes to establish a Gas Infrastructure Replacement Program
(“GIRP”) to recover its costs related the replacement of aging natural gas infrastructure to ensure
the safety and reliability of its gas distribution system. Specifically, ENO proposes to include
GIRP investment made through the end of this proceeding in the costs collected through the
proposed GIRP Rider;224 and
WHEREAS, ENO specifically proposes to replace or abandon a total of 238 miles of lowpressure cast iron and steel and vintage plastic pipes at an estimated cost of $119 million because,
according to the ENO, cast iron and vintage plastic are two of the material types that the natural
gas industry recognizes are prone to failure and recommends should be replaced. 225 ENO also
argues that a gas distribution system that is entirely high-pressure also offers the benefit of

223

Ex. No. ENO-22 at 16:19-17:2.
Id.at 17.
225
Id. at 15.
224

49
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 providing a form of “storm hardening,” as high-pressure operation prevents the infiltration of water
into the system;226 and
WHEREAS, under the assumption that the rates implemented as a result of this rate case
include plant in service through December 31, 2019, 227 ENO proposes to recover its GIRP
investment and expenses that are placed into service and/or expended from January 1, 2020
through March 31, 2020 through the GIRP Rider;228 and
WHEREAS, ENO’s proposal contemplates that it will make a rate filing within 60 days
of March 31, 2020 with new rates to become effective for bills rendered on and after the first
billing cycle of July 2020.229 The percent rate adjustment would be applied to each gas rate class
(i.e., Residential. Small General, Large General, Small Municipal, and Large Municipal) with the
exception of the customers ENO describes as “Non-Jurisdictional.”230 Further, ENO is proposing
quarterly rate redeterminations, with quarterly filings that would be submitted within sixty days
after each subsequent three-month period; and
WHEREAS, the Company proposes that the term of GIRP Rider will be in effect through
2027, regardless of whether an FRP remains in place for ENO.231 If this GIRP Rider is terminated
before 2027, then the Company proposes that the GIRP Rider Rate then in effect would remain in
effect until the Council approves an alternative recovery mechanism;232 and
WHEREAS, none of the Intervenors addressed the proposed GIRP Rider; and

226

Id.
Id.
228
Ex. No. ENO-41 at 49.
229
Id. at 49-50.
230
Ex. No. ADV-6 at 80:4-7.
231
Id. at 52.
232
Id. at 52-53.
227

50
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 WHEREAS, Advisors’ witness Watson testifies that ENO’s proposed GIRP Rider is not
necessary to allow ENO the opportunity to recover its related costs.233 He states that “[t]hese
GIRP-related costs are predictable and manageable by ENO.”

As such, other ratemaking

mechanisms exist to allow ENO the opportunity to recover such costs such as ENO’s proposed
FRP.234 Further, the Advisors note that “ENO witness Bourg testified, ‘ENO agrees that a properly
structured FRP would provide an appropriate means to adjust ENO’s gas rates to allow it to recover
its gas revenue requirements, including its GIRP-related costs and a reasonable return on its
investment;’”235 and
WHEREAS, Advisors’ witness Rogers testifies that although he agrees that the proposed
scope of GIRP is consistent with industry trends to identify risks and replace aging infrastructure
prior to failure and will provide customers with a safer, more reliable gas distribution system, he
expressed his concern regarding the resulting rate impact on ratepayers;236 and
WHEREAS, the Advisors note that the costs related to GIRP investment through 2019 are
estimated to have a bill impact on a typical 100 ccf/month residential customer of approximately
$6.12/month with rates in the instant proceeding. The Advisors further note that the estimated
costs related to GIRP investment after 2019 and the estimated costs related to address historical
underground utility conflicts, the estimated bill impact on a typical 100 ccf/month residential
customer peaks at approximately $20.45/month in 2026;237 and
WHEREAS, the Advisors assert that ENO has not shown that the proposed scope and pace
of the GIRP plan adequately mitigates its rate impact. 238 In this regard, the Advisors argue ENO

233

Ex. No. ADV-6 at 81:9-10.
Id. at 81:11-14.
235
Id. at 82:6-9, citing Rebuttal Testimony of Michelle P. Bourg at 8, (Docket No. UD-07-02) (Sept. 5, 2017).
236
Ex. No. ADV-6 at 39-40:17-10.
237
Ex. No. ADV-6 at 39:18-40.
238
Advisors’ Initial Brief at 90.
234

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 refrained from providing a specific estimate of the approximate number of miles of pipe that should
be replaced annually to ensure the safety of the gas distribution system;239 and
WHEREAS, ENO maintains its position for the original GIRP schedule presented in the
Application;240 and
WHEREAS, the Advisors make the following recommendations: (1) that the Council
approve recovery of the GIRP infrastructure costs incurred as proformed through the end of 2019
as generally approved by Resolution No. R-17-38; (2) that the Council reject ENO’s proposed
GIRP Rider as it constitutes inappropriate single-issue ratemaking and any Council-authorized
GIRP-related costs are more appropriately recovered in base rates as adjusted through the gas FRP
evaluations; and (3) that ENO be required to identify potential measures to mitigate the identified
impact on ratepayers; and
WHEREAS, the Advisors further recommend that given ENO’s unwillingness to depart
from its proposed pace of GIRP-related investments, the Council establish a that a working group
composed of the Advisors, ENO, and Intervenors to explore appropriate cost mitigation
measures;241 and
WHEREAS, the Advisors have noted, and the Council is concerned that, ENO has
changed the scope and cost budget for GIRP, including introducing a utility conflict survey cost
in the instant proceeding and introducing abandonment of plant as a component of GIRP; and
WHEREAS, the Council believes that the safe operation of ENO’s gas distribution system
is the paramount concern but also remains concerned regarding the cost impact on ratepayers with
respect to ENO’s proposed gas infrastructure replacement program; and

239

Id.
Ex. No. ENO-24 at 5:14-16.
241
Ex. No. ADV-2 at 10:19-21.
240

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 WHEREAS, the Council agrees with the Advisors’ recommendations and (1) finds that
the GIRP infrastructure costs through the end of 2019 should be approved so as not to disrupt the
gas infrastructure replacement; (2) rejects ENO’s proposed GIRP Rider as it constitutes
inappropriate single-issue ratemaking and finds that any Council-authorized GIRP-related costs
are more appropriately recovered in base rates; and (3) requires ENO to identify potential measures
to mitigate the cost impact of ENO’s proposed GIRP plan; and
WHEREAS, in light of the considerable need to ensure that ENO’s distribution gas
pipeline operations are safe and reliable, the Council finds that ENO may continue to make prudent
investments in gas distribution plant and incur prudent utility conflict survey costs as required to
ensure the safe operation of ENO’s gas utility, and that a working group should be established to
consider all appropriate measures to mitigate harmful GIRP-related ratepayer impacts, as proposed
by the Advisors; and
ALLOCATION OF CAPACITY COSTS ASSOCIATED WITH CERTAIN PURCHASE
POWER AGREEMENTS
WHEREAS, in proposing customer class revenue requirements, ENO allocated capacity
costs associated with the Resource Plan Purchase Power Agreements (“PPAs”) using the relative
percentage of energy sales (kWh) attributable to each rate class.242 According to the Company,
this allocation method decreases the capacity-related expenses allocated to the residential rate class
and re-allocates those costs among the remaining customer classes.243 According to ENO, the
reallocation occurs as a matter of the Company’s proposed rate design and is not reflected in
ENO’s electric cost of service study;244 and

242

ENO Initial Brief at 81.
Id.
244
Id.
243

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 WHEREAS, Advisors’ witness Prep and CCPUG witness Baron object to the energybased allocation of the Resource Plan PPAs capacity-related expenses; and
WHEREAS, specifically, for the allocation of capacity-related costs from Riverbend 30%
PPA (“Riverbend 30”) and Entergy Arkansas, Inc. Wholesale Base Load PPA (“EAI WBL”),
Advisors’ witness Prep used a production demand allocator, which is consistent with ENO’s own
electric cost of service study, rather than ENO’s kWh/energy allocation of these fixed costs;245 and
WHEREAS, CCPUG argues that ENO should allocate the capacity costs associated with
the EAI WBL and River Bend 30% PPAs to each customer class on an equal percentage basis, just
as it proposes to do with respect to the Ninemile 6 PPA and Algiers Transaction PPA capacity
costs;246 and
WHEREAS, CCPUG asserts that allocation of these costs on an equal percentage basis is
a reasonable and well-accepted method to allocate and recover such fixed, non-fuel capacity costs,
and ENO acknowledges that it is consistent with prior Council rate making decisions;247 and
WHEREAS, CCPUG also points out that ENO proposes to treat the non-fuel, capacity
costs related to the EAI WBL and River Bend 30% PPAs differently than it proposes to treat
capacity costs associated with other PPAs, which are identical in nature;248 and
WHEREAS, ENO argues, to the contrary, that the energy allocation not only is effective
to address residential customer rate impacts, it is also founded on sound policy and cost causation
principles;249 and

245

Ex. No. ADV-3 at 28:2-4.
CCPUG Initial Brief at 15-16.
247
Id. at 15, citing Ex. No.. ENO-41 at 23:11-12. “[I]t has been the Council’s practice to adjust base rates by
applying an equal percentage change to all classes.”
248
Id. at 15.
249
ENO Initial Brief at 82.
246

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 WHEREAS, the Council disagrees with ENO’s proposal to allocate capacity costs related
to the EAI WBL and River Bend 30% PPAs to each customer class on a percentage of energy
(kWh) sales; and
WHEREAS, the Council finds that CCPUG’s concerns regarding the effect of ENO’s
proposed methodology to allocate these costs have merit; and
WHEREAS, the Council also concludes that Advisors’ witness Prep’s recommendation to
require ENO to allocate these capacity costs on a production demand basis, as used in ENO’s
electric cost of service study, is more consistent with the Council’s prior ratemaking decisions than
ENO’s proposal and also similar to ENO’s treatment of other PPAs being realigned into base rates
in this proceeding; and
CCPUG’S PROPOSED RATE ADJUSTMENTS
WHEREAS, CCPUG made a number of recommended rate adjustments in this proceeding
that the Council declines to adopt, including;
a.
b.
c.
d.
e.
f.
g.
h.

Remove Capital Storm Restoration Costs from Plant;
Remove Depreciation Expense Associated With Capital Storm Restoration Costs;
Remove Amortization of Algiers Migration Costs;
Reduce Depreciation Expense – Correct Patterson Solar Depreciation Rate;
Remove Reduction to ADIT for Excess ADIT Amortization in 2019;
Remove Algiers Migration Costs Net of ADIT;
Reduce Depreciation Expense – Use 0% Net Salvage for Union Power Block #1;
Extend Amortization of Algiers Transaction and Migration Costs to 10 Years; and

WHEREAS, the Council has carefully considered each of these recommended
adjustments and finds that they should not be adopted for various reasons; and
WHEREAS, with respect to the adjustment, Remove Capital Storm Restoration Costs
from Plant and Remove Depreciation Expense Associated With Capital Storm Restoration Costs,
the Council is unpersuaded by CCPUG's proposals regarding the recovery of storm related costs

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 and declines to alter the Council’s longstanding practice of allowing the recovery of such costs;
and
WHEREAS, with respect to the adjustment, Remove Amortization of Algiers Migration
Costs, Remove Algiers Migration Costs Net of ADIT and Extend Amortization of Algiers
Transaction and Migration Costs to 10 years, the Council declines to modify its previously
approved Algiers transaction and migration cost amortization period; and
WHEREAS, as for CCPUG’s proposed adjustment Reduce Depreciation Expense Correct Paterson Solar Depreciation Rate, the Council is not persuaded that the Paterson Solar
Project's depreciation rate as proposed by ENO is inappropriate since the project is reasonably
viewed as a technology demonstration pilot project; and
WHEREAS, the Council also finds that the proposed adjustment, Remove Reduction to
ADIT for Excess ADIT Amortization in 2019, would be inconsistent with the accepted ratemaking
principle of allowing ENO the opportunity to recover its costs contemporaneously with their
incurrence, including proforma costs that are known and measurable; and
WHEREAS, CCPUG’s proposed adjustment, Reduce Depreciation expense – use 0% Net
Salvage for Union Power Block #1, should not be adopted because the Council is not persuaded
that Union Power Block #1’s salvage will be 0%; and
WHEREAS, CCPUG did, however, make recommended rate adjustments that the Council
believes should be adopted, including,
a.
b.
c.
d.

Correct Cash Working Capital to Include Dividend Component of Return
on Equity;
Reduce Depreciation Expense – Use 40 Year Service Life for Union Power
Block #1;
Extend Amortization Period for General Plant Reserve Deficiency from 10
Years to 20 Years;
Remove Forecast 2019 Increases in Payroll and Related Expenses; and

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 WHEREAS, with respect to the adjustment, Correct Cash Working Capital to Include
Dividend Component of Return on Equity, the Council believes that this adjustment is reasonable
and is consistent with the Council’s overall goal of reducing base rates to the greatest extent
practicable; and
WHEREAS, with respect to the adjustment, Reduce Depreciation Expense – Use 40 Year
Service Life for Union Power Block #1, the Council adopts the position of CCPUG as discussed
in greater detail herein; and
WHEREAS, with respect to CCPUG’s adjustment, Extend Amortization Period for
General Plant Reserve Deficiency from 10 Years to 20 Years, the Council believes that this
adjustment is consistent with the Council’s decision to use a 40 year service life for Union Power
Block #1 which has the effect of reducing ENO’s revenue requirement while maintaining ENO’s
opportunity to recover its prudently incurred costs; and
WHEREAS, with respect to the adjustment, Remove Forecast 2019 Increases in Payroll
and Related Expenses, the Council finds that this adjustment should be adopted since ENO did not
provide documentation or otherwise establish that these proforma expenses are known and
measurable; and
WHEREAS, CCPUG made some recommended rate adjustments that were opposed by
the Advisors in testimony and that the Council chooses not to adopt, including,
a. Remove Plant, A/D, and ADIT Proforma Adjustments Related to 2019 Additions;
b. Remove Depreciation Expense Related to 2019 Plant Additions; and
WHEREAS, the Council finds that these adjustments are inconsistent with the Council’s
decision in this resolution to generally allow ENO to include proforma costs that are known and
measurable in rate base for the purpose of setting rates in this proceeding; and

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 COST ALLOCATION AND CUSTOMER CLASS REVENUE REQUIREMENTS
WHEREAS, ENO proposes several steps in the way that its total cost of service/revenue
requirement is allocated among customers classes. These steps impact the extent to which various
customer classes see a rate increase or decrease as a result of the overall revenue decrease proposed
by ENO; and
(1)

Cost Allocation

WHEREAS, ENO argues that its proposed cost allocation methodologies have been
historically used by the Company and are consistent with those traditionally approved by the
Council. The significant characteristic of ENO’s cost allocation is the fact that ENO limits its cost
of service allocations to only costs recovered in base rates. ENO’s allocations of all other costs in
the total revenue requirement are effectively determined by ENO’s proposed rider tariff design for
revenue recovery. For example, ENO proposed an allocation of AMI costs (through its proposed
AMI Rider) on the basis of numbers of customers (which heavily weights the AMI cost recovery
on residential); and
WHEREAS, Air Products concurred with the cost allocation methodologies employed by
ENO in the development of its electric class cost of service study, specifically the 12 coincident
peak (“12 CP”) method for the allocation of generation-related fixed costs and PPAs. CCPUG
Witness Baron stated that ENO’s 12 Coincident Peak class cost of service study is a reasonable
basis to evaluate the cost of service for each of the Company’s rate classes; and
WHEREAS, the Advisors generally accepted ENO’s cost allocation methodologies with
few exceptions. The Advisors differed with ENO with respect to the allocations of AMI costs.
Specifically, the Advisors recommend that the cost responsibility for AMI implementation should
be based on the costs and benefits of AMI established in Docket No. UD-16-04; and
(2)

Customer Class Revenue Requirements
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 WHEREAS, ENO’s class cost of service study shows the various customer class rates of
return (limited to base rates rather than total costs of service) that result from present base rate
revenues and the allocation of costs that ENO has identified as related to recovery with base rate
revenues. ENO’s class cost of service study also shows how each customer class present base rate
revenue differs from the customer class revenue that would provide a rate of return equal to that
proposed by ENO; and
WHEREAS, ENO’s proposal for revenue changes by customer class does not follow its
class cost of service allocation study filed in the Application. Neither did ENO use its class cost
of service study to show how its proposed revenue requirements by customer class changed the
various customer class rates of return that correspond to present base rate revenues. Rather ENO
proposed class revenue requirements based on an energy-based class allocation for its proposed
cost allocation with regard to the capacity costs associated with Riverbend 30 (“RB30”) and
Entergy Arkansas, Inc. Wholesale Base Load (“EAI WBL”) Purchased Power Agreements
(PPAs”). ENO used the same approach to implementing the first step of its proposed Algiers
Residential Rate Transition (“ARRT”) plan. Next ENO applied a final class revenue adjustment
pro-rated on present customer class base rate revenues; and
WHEREAS, Air Products witness Brubaker proposed to adjust class revenues by first
calculating the difference between the total revenues ENO requested and the total revenues
awarded by the Council, and then spreading that difference to only those customer classes whose
revenues would be above cost of service under ENO’s rate proposal. Alternatively, CCPUG’s
witness Baron regarded the important issue in this case to be the extent to which the Council
follows the cost of service results in its revenue allocation decision.

However, he then

recommended that base rate revenues be increased by a uniform percentage amount, with a cap on

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 the total revenue change at a 2% increase level. CCPUG also proposed that the first $3.325 million
of Council approved revenue adjustments should be applied to eliminate the increases proposed
for the four Large Industrial classes proposed by ENO to fund ENO’s proposed Algiers residential
mitigation plan; and
WHEREAS, the Advisors’ recommendation is to develop proposed customer class
revenue requirements using ENO’s class cost of service analysis to evaluate how each change to
customer class revenue relates to changes in the customer class rates of return. The Advisors
contend that the Council should be provided such specific information on the relative rates of
return among the customer classes in its determination of the appropriate changes to the revenue
responsibility of each customer class; and
WHEREAS, as proposed by the Advisors, the cost of providing service is related to the
established total revenue for each customer class. When class allocations are finalized for all other
components of the cost of service except return, the class cost of service model provides the
specific information related to discrete changes in present class revenues and rates of return. The
Advisors used this information to make recommendations to the Council regarding individual
customer class revenue requirements while recognizing the disparity among the customer class
rates of return and the impacts of changes to each customer class total present revenue. Thus,
based on the Council approved revenue requirement (cost of service) level for each customer class
in this case, the resulting rates of return for each customer class would then be used in the
subsequent FRP to calculate the return component of the FRP customer class revenue requirement
and the decoupling revenue adjustment. Any adjustments to the relative rates of return should be
movements towards the total utility rate of return; and

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 WHEREAS,. the Council finds that the Advisors’ approach to setting customer class
revenue requirements is a preferred cost-based approach and provides the Council with
information relating revenue changes to impacts on customer class rates of return; and
REALIGNMENT OF RATE STRUCTURE
WHEREAS, ENO proposes to eliminate two obsolete customer classes (Master Metered
Residential and Experimental Interruptible) and to consolidate its Small Electric Service and
Traffic Signal Service classes into a single class. ENO also proposes to consolidate all of its private
area lighting services into a single customer class. ENO Witness Talkington addressed the
proposed combination of Algiers non-residential rates with Legacy ENO rate classes. As a result,
the Company’s electric cost of service studies are based on allocating costs to nine customer rate
classes. ENO proposes to discontinue all existing Algiers rate schedules, except for the Market
Valued Load Modifying Rider (“MVLMR”) and Market Valued Demand Response Rider
(“MVDRR”), which ENO proposes to available all ENO customers and qualified demand response
aggregators of retail customers; and.
WHEREAS, none of the Intervenors contested ENO’s realignment of rate classes and rate
structures; and
WHEREAS, the Advisors do not oppose ENO’s proposal to eliminate and consolidate
customer classes, including the existing Algiers electric tariffs, to be combined into nine electric
customer rate classes; and
WHEREAS, in light of the agreement of ENO and the Advisors regarding the elimination
of the relevant obsolete customer classes and the consolidation, including the existing Algiers
electric tariffs, into nine electric customer rate classes and the lack of opposition from any other
party, the Council approves the proposed rate realignments; and

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 NON-JURISDICTIONAL GAS CUSTOMERS
WHEREAS, Non-Jurisdictional (“NJ”) customers are a subset of industrial customers for
whom ENO provides interruptible gas service pursuant to negotiated special non- published
contracts.250 Advisor witness Prep notes that these customers were not included in ENO gas cost
of service study and as such there is no basis under that approach to determine their allocated cost
responsibility;251 and
WHEREAS, ENO did not address this class of gas customers in its Application or Direct
Testimony.

In response to the Advisors’ testimony, ENO takes issues with the Advisors’

recommendation that NJ customer rates should be reviewed and that, according to ENO, placing
the existing NJ customers on the Large General Service rate would not be in the customer’s best
interest because it would likely result in a material increase in the cost for gas service for this class
of customers. ENO argues that “[b]y offering interruptible service under special contracts to these
customers, gas service should be able to remain competitive with the prices available to other
similar industrial customers with whom the ENO industrial customers are in competition.” 252
ENO also notes that by continuing to serve NJ customers under special contracts also means that
theses interruptible gas customers will be served in a manner similar to the way gas service is
provided to all other industrial customers throughout the state because the natural gas prices paid
by customers classified as industrial are a confidential matter between the customers and the
seller;253 and
WHEREAS, none of the Intervenors addressed NJ gas customers’ rates; and

250

Ex. No. ENO-25 at 27.
Ex. No. ADV-3 at 50.
252
Ex. No. ENO-25 at 30.
253
Id.
251

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 WHEREAS, the Advisors assert that ENO’s use of “NJ” to refer to these customers is a
misnomer because the rates or charges applied to any person or entity receiving gas or electric
service in New Orleans are subject to Council retail rate regulation. Since NJ customers receive
gas service through the same gas distribution system mains as do all other ENO gas customers and
all NJ customers are located in New Orleans, the Advisors contend that NJ customers are subject
to Council retail rate regulation;254 and
WHEREAS, although there is no NJ customer cost analysis, the Advisors argue that NJ
customers’ rates and established business operations in New Orleans should not be modified
without careful Council evaluation. Instead, the Advisors recommend: (1) that ENO should be
required to provide a complete cost of service analysis in support of the NJ customers’ rates as
part of future Council rate actions; (2) that the Council affirm that the terms under which ENO
offers gas service to the NJ customers are subject to Council retail rate regulation; (3) that the
Council direct ENO not to execute any new NJ contracts without express Council approval; 255 and
WHEREAS, the Council agrees that NJ customers are subject to the Council’s rate
regulation authority and the Council finds that the Advisors’ argument that the Council in the
exercise of that authority should carefully evaluate whether NJ rates are just and reasonable and in
the public interest. Thus, we direct ENO to provide a complete cost of service analysis in support
of the NJ customers’ rates as part of ENO’s 2020 gas FRP filing; and
NEW RIDERS FOR COST RECOVERY
WHEREAS, ENO is proposing several new or revised riders, each of which would allow
ENO contemporaneous and nearly exact recovery of its related cost. The riders include:

254
255

Id. at 52.
Id. at 55-56.

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 

Fuel Adjustment Clause rider (“FAC Rider”): recovery of fuel and
energy costs, including the recovery of certain power purchase
agreement (“PPA”) related capacity costs;



Purchase Gas Adjustment Clause Rider (“PGA Rider”): recovery of
costs related to the provision of gas sold to ENO’s retail customers;



Midcontinent Independent System Operator, Inc. Rider (“MISO
Rider”): recovery of costs charged to ENO pursuant to the MISO
Open Access Transmission Energy and Operating Markets Tariffs
that are not recovered via the Fuel Adjustment Clause;



Purchase Power and Capacity Acquisition Cost Recovery Rider
(“PPCACR”): recovery of certain PPA-related capacity costs, LongTerm Service Agreement (“LTSA”) costs, and the non-fuel revenue
requirement related to future constructed and/or acquired capacity
additions;



Distribution Grid Modernization Rider (“DGM Rider”): recovery of
costs related to certain distribution investments and O&M expenses
characterized by ENO as relating to grid modernization;



Interim Energy Efficiency Cost Recovery Rider (“EECR Rider”):
recovery of costs related to the Council’s Energy Smart program
over an interim period;



Demand-Side Management Cost Recovery Rider (“DSMCR
Rider”): recovery of costs related to the Council’s Energy Smart
program upon the expiration of Interim EECR Rider;

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 

Gas Infrastructure Replacement Program Rider (“GIRP Rider”):
recovery of costs related to gas distribution investment beyond 2019
and recovery of utility conflict survey costs; and



Advanced Metering Infrastructure (“AMI”) Charge for Electric
Service (“AMICE Rider”)/Advanced Metering Infrastructure
Charge for Gas Service (“AMICG Rider”): recovery of net costs
related to AMI deployment beyond 2019 for electric and gas
respectively; and

WHEREAS, in support of these riders, ENO argues that utilities are currently undergoing
a paradigm shift caused by the need for large new capital additions at a time of increasing costs
and decreasing average usage per residential customer and that a regulatory environment that
provides for contemporaneous cost recovery of large investments outside of the traditional rate
case provides the utility the necessary opportunity to earn its allowed return while continuing to
invest in the system and mitigate operational risks; and
WHEREAS, in contrast, the Advisors urge caution in using riders as cost recovery
mechanisms. To eliminate single-issue ratemaking, the Advisors recommend that the Council
deny ENO’s request for Council approval of certain riders that would provide exact cost recovery
for their respective costs, i.e., a near-guarantee that ENO will recover all of its costs
contemporaneous with their incurrence or through a true-up mechanism involving carrying costs
for any under collection balance; and
WHEREAS, the Advisors note that historically, riders were only approved by regulators
in rare instances to address volatile and uncontrollable costs, such as the recovery of fuel and
purchased power costs or natural gas commodity costs through a fuel adjustment rider or purchased

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 gas adjustment rider. Advisor witness Rogers testifies that typically, riders are used for costs that
can be significantly variable in nature and outside the control of utility. This is the case with
respect to ENO’s FAC, PGA, and MISO riders. At other times, riders may be used to provide for
the recovery of significant costs incurred between full rate case proceedings that were not
otherwise accounted for in base rates; and
SINGLE-ISSUE RATEMAKING
WHEREAS, the Advisors raise significant concerns regarding ENO’s request for Council
approval of riders that would provide exact cost recovery for their respective costs (i.e., a nearguarantee that ENO will recover all of its costs contemporaneous with their incurrence or through
a true-up mechanism involving carrying costs for any under collection balance). Specifically, the
Advisors recommend that such riders should be rejected when they constitute inappropriate singleissue ratemaking. Advisor Witness Watson testifies that single-issue ratemaking is a deviation
from the accepted regulatory ratemaking principle that rates should generally be based on a utility’s
overall costs and risks. The Supreme Court of Louisiana has found that: “[s]ingle issue ratemaking
occurs when a utility’s rates are altered on the basis of only one of the numerous factors that are
considered when determining the revenue requirements of a regulated utility.” Said differently,
single-issue ratemaking occurs when particular portions of a utility’s revenue requirement are
considered for recovery in isolation from the utility’s total costs and revenues; and
WHEREAS, the Advisors also note that “[s]ingle-issue ratemaking is generally not
appropriate because its application is contrary to the generally accepted regulatory ratemaking
principle that a utility’s rates that produce its revenues should be based on a utility’s overall costs.
Single-issue ratemaking may not capture the overall impact of the portion of a utility’s revenue
requirement under special consideration by potentially not reflecting offsetting changes in other
areas of the utility’s operations; and
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 WHEREAS, single-issue ratemaking may have the adverse impact of reducing a utility’s
incentive to control its costs to the extent such ratemaking guarantees cost recovery through a trueup mechanism.

As such, single-issue ratemaking is particularly inappropriate when other

ratemaking mechanisms that are not subject to single-issue ratemaking deleterious effects are
available, such as recovery of the same costs through base rates; and
WHEREAS, it should be noted that the Advisors do not recommend an across-the-board
prohibition riders as recovery mechanisms, acknowledging that there may be valid and supportable
reasons to use a Rider to recover certain costs of service. The Advisors note that a Rider may be
acceptable if the specific costs are substantial, vary significantly and/or are unpredictable, or
require periodic review by the Council. In those instances, the Advisors recommend that an
appropriately selected Rider should generate revenue from each customer class based on the costs
determined to be recovered from each customer class as reflected in the allocation of the total cost
of service; and
WHEREAS, the Advisors also note that a utility is entitled only to the opportunity to earn
a reasonable return on its investment, and that the law does not insure that a utility will in fact earn
the particular rate of return authorized by a Commission or even that it will earn any net revenues.
ENO should be allowed a reasonable opportunity to recover its prudently incurred costs and earn
a reasonable return on its investments. The reasonable return on investment is primarily influenced
by the Council setting a ROE at a level that is comparable to that being earned by other companies
with comparable risks, maintains ENO’s financial integrity, and maintains ENO’s ability to raise
capital; and
WHEREAS, in response to ENO’s argument that its proposed rider address the risk of
undue regulatory lag, the Advisors note that if their recommendation for an annual electric and gas

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 FRPs for a period of three years is approved the FRPs will help to mitigate ENO’s concerns related
to regulatory lag because the FRP would provide for an annual adjustment to ENO electric and gas
rates to reduce the time between regulatory base rate actions. Additionally, to further mitigate
regulatory lag, the Advisors recommend that ENO be allowed to include prospective proforma
adjustments for known and measurable capital additions budgeted for the 12-month period
immediately following the FRP test year. Thus, ENO’s known and measurable costs that will
occur in the rate effective period will be reviewed and considered for recovery in the annual FRP
process; and
GRID MODERNIZATION
WHEREAS, ENO contends that its grid modernization investments differ from grid
maintenance investments in that the latter costs are typically incurred as part of a utility’s ordinary
course of business and are required for a utility to continue to provide reliable service in the short
term.256 According to ENO, grid maintenance investments are typically reactive in nature and are
incurred due to problems presented by existing equipment (e.g., replacing damaged or aging assets,
addressing compliance issues, etc.). In contrast, grid modernization investments are proactive
investments designed to enhance the functionalities and services that grid infrastructure can
provide to customers, while also changing the paradigm for evaluating and maintaining the
reliability of the distribution system; and257
WHEREAS, ENO also notes that the five current grid modernization projects that were
discussed in ENO’s Application and testimony are expected to improve reliability by reducing the
number of customer interruptions by more than 53,000 per year and lowering the number of

256
257

Ex. No. ENO-6 at 34:13-35:5.
Id.

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 customer minutes of experienced interruptions by approximately 7.2 million per year.258 The costs
for these projects are estimated at $59.3 million259 through January 31, 2022, of this amount $12.8
million is funded through ratepayer savings due to the effects of the TCJA.260 Prudently-incurred
costs related to the remaining $46.5 million, would be appropriately recoverable through rates.
Additionally, ENO proposes that the investment associated with the portions of the grid
modernization projects expected to close to plant in service by December 31, 2019, be reflected in
base rates adopted in this proceeding;261 and
WHEREAS, with regard to portions of the above projects closing after December 31,
2019, and any future grid modernization projects, ENO is proposing that the Council, in this
proceeding, approve Rider DGM as the cost recovery mechanism. As proposed, Rider DGM
would consist of a charge based on a percentage of base rates that is incremental to base rates and
would recover depreciation and return on grid modernization investments made in the applicable
year. The rider would be updated on a quarterly basis to include any new investments made in the
preceding three months for the grid modernization projects described above, or for future grid
modernization projects;262 and
WHEREAS, AAE and CCPUG oppose the proposed DGM rider. According to AAE,
ENO did not provide any justification for this choice of rate structure.263 Further, AAE asserts that
the DGM rider “effectively increases the fixed customer charge, and therefore reduces consumer
incentives for energy conservation.” 264

AAE also argues that ENO’s grid modernization

investments are investments in the shared distribution system and do not encompass any customer-

258

Ex. No. ENO-8 at 24:5-7.
Ex. No. AAE-3 at 35:7-8.
260
Tax Cuts and Jobs Act of 2017, Pub, L. 115-97, 131 Stat. 2054, December 22, 2017.
261
Ex. No. ENO-41 at 54:1-2.
262
Ex. No AAE-3 at 35.
263
Ex. No. AAE-3 at 36:4-13.
264
Id.
259

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 related functions or involve costs that otherwise vary directly with the number of customers on the
system or connecting a customer to the system. 265 Thus, AAE states that the charge is
unreasonable both from a perspective of public policy in support of energy efficiency, and from
the perspective of cost causation;266 and
WHEREAS, AAE’s also contends that the charges to be recovered in Rider DGM should
be aligned with how the Company charges for distribution service more generally, i.e., recovery
through base rates. Noting that the current five projects target reliability improvements rather than
demand growth, the charge associated with these investments should also be volumetric for nonresidential customers;267 and
WHEREAS, CCPUG argues that “[i]f the EFRP and GFRP are adopted, they likely will
result in annual rate increases starting in 2020. If the DGM Rider and/or GIRP Rider are adopted,
they will result in quarterly rate increases starting in 2020. These rider increases will be above
and beyond any rate increases resulting from the electric and gas FRPs or any future base rate
proceeding unless and until these riders are terminated”;268 and
WHEREAS, the Advisors contend that the proposed DGM Rider would allow ENO
quarterly rate adjustments to recover expected costs related to grid modernization investments and
provides for an annual true-up of rider collections versus actual revenue requirements. As such,
the DGM Rider constitutes guaranteed exact cost recovery of certain distribution investments that
ENO has classified as grid modernization.269 Moreover, the Advisor emphasize that these costs

265

Id.
Id.
267
Id. at 36-37.
268
Ex. No. CCPUG-1 at 4:15-19.
269
Ex. No. ADV-7 at 88:9-11 (HSPM).
266

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 are predictable and within ENO’s control, thus lacking the cost attributes (unpredictable and
volatile) that generally require recovery through a Rider;270 and
WHEREAS, the Council agrees with the Intervenors and the Advisors that ENO’s DGM
Rider is unnecessary. As the Advisors correctly note that the DGM Rider constitutes inappropriate
single-issue ratemaking because it sets a separate rate recovery mechanism for ENO’s incremental
distribution investments.271 Further, the DGM rider is not necessary to allow ENO the opportunity
to recover its prudently-incurred costs, as other ratemaking mechanisms, i.e., base rates and FRP,
are available to allow ENO recovery of its grid modernization-related costs;272 and
ALGIERS RESIDENTIAL MITIGATION PLAN
WHEREAS, the Advisors note that one goal of the Council to be implemented in this rate
proceeding is to address the disparity between the revenues provided by the present rate tariffs for
Algiers residential customers and Legacy ENO residential customers. 273 According to ENO’s
Application, the typical Algiers residential monthly bill (1,000 kWh/mo.) is $104.28 as opposed
to $122.11 for customers on the East Bank.274 The Council, in Resolution No. R-17-504, directed
ENO to present one combined cost of service study and one combined set of rate schedules for the
Legacy ENO and Algiers customers, “unless significant rate shock could occur to single or
multiple classes of customer[s];”275 and
WHEREAS, under the Company’s proposed combined residential rate without any rate
mitigation, according to ENO’s Application a typical residential Algiers monthly bill would see a

270

Id. at 89:6-7 (HSPM).
Id. at 86:20-21 (HSPM).
272
Id. at 89:15-17 (HSPM).
273
Advisors Initial Brief at 54.
274
Ex. No. ENO-55, Statement A-5; Advisors’ Initial Brief at 54.
275
Ex. No. ENO-55 at 27, quoting Resolution No. R-17-504.
271

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 $16.16 increase or 15.50%,276 which the Advisors consider a wholly unacceptable impact.277 In
order to reduce the rate shock for Algiers residential customers that would otherwise result from a
strict adherence to ENO’s proposed residential revenue requirement and a combined residential
rate, ENO proposed to phase-in the revenue increase to Algiers residential customers so that an
Algiers residential customer’s typical bill increases no more than 3.5% per year;278 and
WHEREAS, as proposed by ENO, the first step of the phase-in will be implemented as a
part of the rates ultimately approved by the Council in this case and Algiers bills would increase
by 3.5%, or approximately $3.65 on a typical residential bill.279 The second step of the phase-in
would be in September 2021, at the same time as the annual revenue adjustments that would be
authorized under its proposed FRP. 280 ENO notes that the second step in 2021 foregoes an
additional ARRT-related increase for Algiers customers in 2020, when the NOPS is tentatively
scheduled to be included in ENO rates.281 As proposed, Algiers residential bills will increase in
2021 by another 3.5%, or $3.76 on a typical residential monthly bill, moving them closer to parity
with other Legacy ENO residential customers;282 and
WHEREAS, in order to implement the ARRT plan proposed by ENO, the costs that
Algiers residential customers would otherwise pay under the combined rate are paid for by four
other participating rate classes - Large Electric, Large Electric High Load Factor, High Voltage,
and Large Interruptible rate classes, classes that would otherwise receive an overall bill reduction
of 10% or more as a result of the proposed rates.283 These industrial rate classes would see an

276

Ex. No. ENO-2 at 14:14-18.
Ex. No. ENO-45, at Exhibit MLT-3; Advisors’ Initial Brief at 54.
278
Ex. No. ENO-45 at 30:8-17.
279
Id. at 30:8-11, Exhibit MLT-3; ENO Initial Brief at 88.
280
ENO-45 at 30:21-31:1.
281
Ex. No. ENO-55 at 28.
282
Ex. No. ENO-45 at 30:13-17, Exhibit MLT-3; ENO Initial Brief at 88.
283
ENO Initial Brief at 88-89.
277

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 offsetting rate reduction in September 2021 when the second step increase is implemented for
Algiers residential customers;284 and
WHEREAS, ENO proposes a Base Rate Adjustment Rider to implement the ARRT plan.
The rider contemplates two step changes in the rates of the Algiers residential customer and other
four participating classes;285 and
WHEREAS, Air Products, BSI and AAE do not address ENO’s proposed ARRT plan; and
WHEREAS, CCPUG does not oppose ENO’s ARRT Plan but argues that it should be
modified such that the first $3.325 million of any reduction in ENO’s proposed base rate revenue
requirement increase are designated for the Large Electric, Large Electric High Load Factor, High
Voltage, and Large Interruptible rate classes that would bear the funding for ENO’s ARRT
proposal;286 and
WHEREAS, the Advisors propose a residential combined rate adjustment for Algiers,
which would be a revenue adjustment between Legacy ENO residential customers and Algiers
residential customers and would be applied with each prospective annual rate action until parity
was reached.287 Instead of ENO’s proposed 3.5% increase to Algiers residential customers, the
Advisors propose that Algiers’ residential customers would have no initial revenue change in the
instant docket.288 The Advisors propose that subsequent to the instant proceeding and under a
combined residential rate, the adjustment could increase Algiers residential revenue 4%, with a
corresponding adjustment to Legacy ENO customers such that the combined adjustment would
reflect the revenue change for the total residential class.289 If the total residential revenue increase

284

ENO Initial Brief at 88.
Ex. No. ENO-45 at 31:14-20.
286
CCPUG Initial Brief at 19.
287
Advisors Initial Brief at 57.
288
Id.
289
Id.
285

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 was less than 4%, Algiers residential revenue would be increased 4% in subsequent rate actions
and the increase to Legacy ENO residential would be moderated accordingly to reflect the total
residential class increase. If a prospective ENO-wide residential revenue increase was greater than
4%, all residential customers, including Algiers, would receive the revenue change exceeding
4%;290 and
WHEREAS, the Advisors explain that their Algiers proposal could be implemented in the
context of a Rider applicable to the combined residential base rate tariff and would extend to future
rate actions as necessary;291 and
WHEREAS, the Advisors note that the CCPUG proposal would, in effect, transfer the
funding of Algiers mitigation to all other customers except those four large industrial customer
classes.292 CCPUG argues, however, that it would simply eliminate the subsidy;293 and
WHEREAS, ENO proposes to achieve the Algiers mitigation through implementation of
a rider, while the Advisors propose a base rate tariff alternative.294 ENO opposes implementing
Algiers residential customer mitigation through changes to the existing residential base rate tariff
arguing that it would add significant unnecessary complexity to the tariff design and billing of
residential customers with the potential for unnecessary customer confusion.295 ENO also opposes
the alternative of making future AART rate changes in the context of the FRP, arguing that
implementing the change through the larger context of the FRP dilutes the extent to which the
annual adjustments address the disparity between residential customers and does not assure that
the disparity will be eliminated in a reasonable time frame;296 and

290

Id.
Id. at 58.
292
Id. at 56.
293
CCPUG Reply Brief at 28.
294
ENO Initial Brief at 91.
295
Id.
296
Id. at 92.
291

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 WHEREAS, ENO also opposes CCPUG’s proposal that the first $3.325 million of any
Council-approved revenue adjustment to ENO’s requested revenue requirements be used to
eliminate ENO’s proposed Base Rate Adjustment Rider changes to large customers. 297 ENO
argues that this proposal improperly intermingles the establishment of the overall revenue
requirement with the class allocation of that revenue requirement;298 and
WHEREAS, the Council agrees with ENO and the Advisors that under the new combined
residential rate, it is necessary to mitigate the revenue related to Algiers residential customers. The
Council agrees with the Advisors that since a the majority of customers will receive a general rate
reduction from the instant proceedings, the Algiers mitigation plan should have no change for
Algiers residential revenue; and
WHEREAS, all parties appear to support rate mitigation for Algiers residential customers.
The most significant difference between ENO’s mitigation proposal and the Advisors’ mitigation
proposal is that ENO’s approach would reallocate revenues from the Algiers residential class to
the classes that would otherwise receive the largest rate decreases of any of the customer classes,
while the Advisors’ approach would reallocate revenues from the Algiers residential customers to
the Legacy ENO residential customers which would reduce the amount of rate decrease they would
otherwise receive in the instant docket under the combined rate; and
WHEREAS, while the Council appreciates that general ratemaking principles would
suggest keeping all residential costs and revenues within the residential class, in light of the
specific facts of this case, the Council finds that it serves the public interest better to reallocate the
revenues to the classes that would otherwise receive the largest rate decrease. The Council finds
that the Algiers mitigation will be funded from the Large Electric, Large Electric High Load

297
298

Id. at 93; ENO Reply Brief at 54.
Id.; ENO Reply Brief at 54.

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 Factor, High Voltage, and Large Interruptible rate classes in proportion to their base rate revenue
requirements; and
WHEREAS, the other primary difference between ENO’s proposal and the Advisors’
proposal is the timing and size of the increases to Algiers’ rates. The Council finds that, consistent
with the Advisors’ recommendations, there will be no revenue change for Algiers residential
customers in the initial rates set in this proceeding. Starting in 2021 with rates effective with that
year’s FRP evaluation, Algiers residential revenue will increase by a minimum of 4%, or equal to
the residential class revenue increase when greater than 4%, until parity is achieved with the
remainder of the residential rate class; and
WHEREAS, the Council agrees with the Advisors that the adjustment should be tied to
the E-FRP. The Council finds that significant rate increases related to the E-FRP, if added to a 4%
rate increase due to the Algiers residential mitigation plan could result in an unreasonable rate
increase in a particular year; and
WHEREAS, the Council finds that subsequent to the final order designating the residential
class revenue requirement, ENO should develop the combined residential rate tariff that provides
the designated revenue impact to Legacy ENO residential as well as the revenue mitigation
required to maintain Algiers residential revenue at present levels without an increase. The Council
also finds that a specific rider tariff should be used to identify the amount of Algiers residential
mitigation revenue required from each of the identified four rate classes based on the fixed cost
portion of their customer class revenue requirements as designated in the final Order of this
proceeding; and

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 ADJUSTMENTS TO FUEL ADJUSTMENT CLAUSE (“FAC”) RIDER
WHEREAS, ENO proposes several changes to its FAC Rider. The first is to combine the
separate FAC riders for Legacy ENO customers and Algiers customers into a single FAC Rider
for all customers.299 ENO also proposes: (1) to modify the recovery of the Resource Plan PPA
capacity expenses to include recovery of the difference between estimated monthly capacity
expenses and that amount recovered through base rates and, and the actual monthly capacity
expenses; (2) elimination of the recovery of LTSA expenses, which ENO proposes to recover
through base rates and the PPCACR Rider; (3) elimination of the Grand Gulf repricing mechanism
for Algiers Customers, (4) elimination of the allocation to Legacy ENO customers of Union Power
Block #1 fuel costs and wholesale revenues so that all customers are allocated these expenses and
benefit from these revenues; (5) combination of the two over/under balances into a single
over/under balance; and (6) use of per book rider revenue instead of calculated FAC collections;300
and
WHEREAS, the Advisors state that the proposed combined FAC Rider is significantly
simpler than the rider it is intended to replace and produces a single FAC Rider rate for both Legacy
ENO Customers and Algiers Customers by eliminating the Geographic-Specific adjustments.301
The Advisors believe this represents a significant improvement with respect to ease of calculation
and understanding.302 The Advisors did, however, note some errors in the formulas and references
and also an inconsistency in the formulas in ENO’s Exhibit No. SMC-2 for the treatment of certain

299

Ex. No. ENO-55 at 30.
Id. at 31; see also, Ex. No. ENO-44 at 5:1-6:12.
301
Advisors’ Initial Brief at 95, citing Ex. No. ADV-1 at 23:7-9.
302
Id., citing Ex. No. ADV-1 at 23:9-10.
300

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 costs as compared to historical treatment and the treatment proposed in ENO’s proposed PPCACR
Rider for similar costs;303 and
WHEREAS, ENO submitted no testimony in response to the errors noted by the Advisors,
rather, ENO stated that there are no substantive disputes regarding the FAC Rider Schedule.304
ENO stated that the only outstanding issue concerns which over and under collections, if any,
should be included in the rider, which is dependent on the final resolution of allocation issues.305
ENO proposes that this component of the rider be addressed in the compliance filing process.306
The Advisors support this suggestion, and therefore recommend that the Council approve the
proposed FAC Rider Schedule, as corrected by the Advisors;307 and
WHEREAS, ENO supports the Advisors’ corrections to the FAC Rider;308 and
WHEREAS, in light of the agreement of ENO and the Advisors as to the corrections and
the lack of opposition from any other party, the Council approves the proposed FAC Rider as
corrected by the Advisors; and
PURCHASED GAS ADJUSTMENT RIDER
WHEREAS, ENO proposes to use per book PGA Rider revenue instead of calculated PGA
Rider collections in order to ensure a more accurate calculation by reflecting customer billing
corrections recorded in the operations month;309 and
WHEREAS, the Advisors note that the proposed combined PGA Rider is similar to the
rider it is intended to replace.310 The Advisors explain that ENO has proposed modifications from

Advisors’ Initial Brief at 95, citing Ex. No. ADV-1 at 23:11-27:8.
Ex. No. ENO-3 at 6:5-7; see also, ENO Post-Hearing Brief at 178.
305
Ex. No. ENO-3 at 6:7-9; see also, ENO Post-Hearing Brief at 178-179.
306
Ex. No. ENO-3 at 6:9-10.
307
Advisors’ Initial Brief at 96.
308
ENO Reply Brief at 118-119.
309
Advisors’ Initial Brief at 96, citing Ex. No. ENO-55 at 31.
310
Id., citing Ex. No. ADV-1 at 28:1.
303
304

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 the previous rider to revise the formulas for calculating the over/under balance to utilize per book
PGA Rider revenue.311 A similar treatment is included in ENO’s proposed FAC Rider, and the
change in the source data for the calculation will not make a material difference in the rate charged
under the FAC Rider or PGA Rider.312 The Advisors did note some errors in the formulas of the
proposed PGA Rider and recommend the Council approve the Rider as corrected for these
errors;313 and
WHEREAS, ENO recommends that the Council approve the proposed PGA Rider subject
to the correction of the errors identified in Advisors’ Exhibit No. JWR-5;314 and
WHEREAS, in light of the agreement of ENO and the Advisors as to the corrections and
the lack of opposition from any other party, the Council approves the proposed PGA Rider as
corrected by the Advisors; and
PPCACR
WHEREAS, ENO explains that, effective with new base rates from this proceeding, it will
no longer recover the Union PB1 and Ninemile 6 PPA costs exclusively through the Rider
PPCACR. 315 ENO proposes to transfer current Rider PPCACR costs relating to the UPS
acquisition and the Ninemile 6 PPA into base rates in this proceeding, and then reset the PPCACR
Rider at zero. 316 On a going-forward basis, ENO then proposes to include three types of
recoverable costs in revised Rider PPCACR: (1) the incremental difference between the estimated,
approved PPA and LTSA costs in the new base rates and the actual PPA and LTSA costs incurred
on a monthly basis; (2) costs related to newly constructed and/or acquired capacity; and (3) costs

311

Id., citing Ex. No. ADV-1 at 28:1-3.
Id., citing Ex. No. ADV-1 at 5-7.
313
Id., citing Ex. No. ADV-1 at 28:8-29:6.
314
ENO Post-Hearing Brief at 179; see also ENO Reply Brief at 119.
315
Advisors’ Initial Brief at 96.
316
Id. at 96-97.
312

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 related to new PPAs the Company may enter into as approved by the Council.317 ENO proposes
to allocate the Rider PPCACR revenue requirement to the rate classes using the base rate revenue
requirement allocation methodology approved by the Council in this proceeding.318 Similar to the
current PPCACR Rider, ENO proposes a cumulative over/under calculation that compares the
cumulative over/under balance and the applicable monthly costs to the PPCACR Rider Revenue
for that operations month.319 Any prior period adjustments will be added or subtracted and an
interest component will be applied based on the average of the beginning of the month and end of
the month cumulative over/under balance for the operations month using that month’s prime
interest rate;320 and
WHEREAS, Air Products supports the PPCACR Rider to allocate cost recovery as an
equal percent of base rate revenue as reasonable in the absence of the utility to use a more specific
cost-based allocation;321 and
WHEREAS, CCPUG argues that it is inappropriate to allow ENO to include any and all
revenue requirements for newly constructed or acquired capacity or the expenses related to new
PPAs and new LTSAs ENO may enter into through a PPCACR Rider.322 CCPUG argues that
doing so would inappropriately allow ENO to include these costs without review or further action
by the Council other than the initial estimated revenue requirement for newly constructed or
acquired capacity.323 CCPUG recommends that the proposed tariff be modified so that no revenue
requirement for newly constructed to acquired capacity or no expenses for new PPAs or LTSAs
may be included without action by the Council and without an opportunity for the Council to

317

Id. at 97.
Id.
319
Id.
320
Id.
321
Ex. No. AP-3 at 19:3-5.
322
Ex. No. CCPUG-1 at 53:8-11.
323
Id. at 53:11-14.
318

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 review the reasonableness of the transactions and agreements as well as setting forth a process to
allow intervenors to review the transactions and agreements as well as the revenue requirements
and expenses that will be included in the rider;324 and
WHEREAS, the Advisors argue that while a rider to permit contemporaneous recovery of
PPA and LTSA costs may be appropriate, the scope of the rider should not be so broad as to
encompass any as-yet unknown non-fuel revenue requirements related to construction and/or
acquisition of new capacity, new PPA, or new LTSA.325 Proposed PPCACR Rider is not necessary
to allow ENO a reasonable opportunity to recover its prudently incurred costs related to future
ENO-owned capacity additions, because mechanisms exist to allow ENO the opportunity to
recover such costs.326 Such non-fuel costs for new acquisitions, once known and measurable, are
more appropriately addressed in a general rate proceeding where all of ENO’s cost categories and
magnitude of costs are considered in total.327 The PPCACR Rider would set a separate rate for
incremental ENO-owned capacity additions and ensure ENO exact cost recovery, which
constitutes inappropriate single-issue ratemaking;328 and
WHEREAS, the Advisors argue that because the timing of any new construction and/or
acquisition of new capacity, new PPA, or new LTSA is currently unknown as are the magnitude
of any costs associated with the unknown future capacity additions, consideration in this instant
base rate proceeding is not appropriate.329 Additionally, the proposed PPCACR Rider allocates
costs to rate classes using a Base Rate Revenue Requirement allocation factor, but since the costs
proposed for recovery in this rider are non-fuel costs associated with production plant, a Production

324

Id. at 54:5-11.
Advisors’ Initial Brief at 98, citing Ex. No. ADV-1 at 32:3-6.
326
Id., citing Ex. No. ADV-6 at 86:9-11.
327
Id., citing Ex. No. ADV-1 at 32:6-10.
328
Id., citing Ex. No. ADV-6 at 17-7:2.
329
Id. at 98-99, citing Ex. No. ADV-1 at 32:10-13.
325

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 Demand Allocation Factor would be more appropriate and consistent with how the costs would be
anticipated to be allocated in a base rate proceeding;330 and
WHEREAS, the Code of the City of New Orleans, Sec. 158-732(c) requires ENO to seek
Council approval for taking an interest in a transmission or generation facility or for entering into
a PPA whose costs generally exceed 2% of the rate making value of ENO’s property.331 ENO can
reasonably request that the Council approve cost recovery relief as part of any such application;
therefore, there is no need at this time for the Council to approve such currently unknown costs to
be recovered through the proposed PPCACR Rider.332 To that end, the Advisors recommend that
(1) costs for non-fuel revenue requirements related to construction and acquisition of new capacity,
fixed costs associated with new PPAs, and costs associated with new LTSAs not be provided
automatic recovery in the proposed PPCACR Rider, and that the name of the rider be changed to
the Purchase Power Cost Recovery Rider (“PPCR”); (2) that the new PPCR Rider collect the
difference (positive or negative) between the estimated PPA capacity and LTSA expenses in the
new base rates from this proceeding (Schedule A costs) and the actual PPA capacity and LTSA
expenses incurred by ENO on a monthly basis; (3) costs recoverable in the PPCR Rider be limited
to costs associated with ENO’s existing PPAsand long term service agreements including: Grand
Gulf UPSA, EAL Resource PPA, Riverbend PPA, Ninemile 6 PPA, Algiers Slice of System PPA,
and LTSA Costs associated with the following facilities: Union PB1, Ninemile 6, Perryville 1
(Algiers SOS PPA), and Acadia (Algiers SOS PPA); (4) the Schedule A costs identified in the new
PPCR be those costs identified in the HSPM Exhibit OT-2, broken down by month; (5) the new
PPCR Rider allocate costs to rate classes using the Production Demand Allocation Factor

330

Id. at 99, Ex. No. ADV-1 at 32:13-18.
Id., Ex. No. ADV-8 at 3-6.
332
Id., Ex. No. ADV-2 at 6-9.
331

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 determined in this proceeding; and (6) the Council implement a new PPCR Rider that is based on
the redline of ENO’s proposed PPCACR Rider provided as Exhibit No. JWR-6 attached to Exhibit
No. ADV-1;333 and
WHEREAS, CCPUG objects that the proposed PPCACR Rider would inappropriately
allow near automatic recovery of new capacity costs and costs of newly-constructed generating
assets without full certification review by the Council.334 CCPUG also argues that the PPCACR
is also unnecessary as any new investment costs it would recover may be recovered through ENO’s
proposed E-FRP;335 and
WHEREAS, CCPUG states it is not opposed to the Advisors’ recommendations for the
(to-be-renamed) Purchased Power Cost Recovery Rider (“PPCR”);336 and
WHEREAS, the Council agrees with the concerns stated by the Advisors and CCPUG;
and
WHEREAS, the Council directs ENO to revise its proposed PPCACR Rider in accordance
with the Advisors’ recommendations for a PPCR Rider; and
MISO COST RECOVERY RIDER
WHEREAS, consistent with the combination of Legacy ENO and Algiers customers,
ENO proposes a combined MISO Cost Recovery Rider that for the most part mimics the current
separate MISO Riders, though certain now inapplicable costs have been eliminated from the
formula. 337 The combined MISO Cost Recovery Rider would be re-determined annually and
subject to annual true-ups beginning in 2020.338 ENO also proposed to use this combined rider in

333

Id. at 99-100, citing Ex. No. ADV-1 at 33:14-34:16.
CCPUG Reply Brief at 30.
335
Id.
336
Id. at 31.
337
Advisors’ Initial Brief at 100, citing Ex. No. ENO-55 at 31; Ex. No. ENO-41 at 40:12-15.
338
Id., citing Ex. No. ENO-55 at 31; Ex. No. ENO-41 at 40:15-18.
334

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 the 2019 MISO Rider filing in order to facilitate the transition from the two current riders and two
sets of rates to the combined rates expected to become effective in August 2019.339 The general
purpose of the MISO Cost Recovery Rider is to define the procedure by which ENO shall
implement and adjust rates contained in the designated rate classes for recovery of the costs,
including, but not limited to, costs charged to ENO pursuant to the FERC-approved MISO Open
Access Transmission Energy and Operating Markets Tariffs that are not recovered via the FAC.340
The Combined MISO Rider revenue requirement would reflect the following costs and revenues:
(1) estimated Net MISO Charges or Credits (i.e., MISO charges and credits for which recovery
has not been requested separately through the FAC), and (2) a true up of actual revenues to actual
costs, including carrying charges;341 and
WHEREAS, the Advisors have reviewed the proposed rider and supporting testimony and
did not find any reference errors or calculation errors.342 The Advisors’ analysis indicates that the
proposed rider is consistent with the directions given to ENO by the Council in Resolution No. R17-504 to develop a single set of proposed tariffs applicable to all customers, that its cost allocation
is appropriate and that the cost categories and adjustment calculations that ENO removed are no
longer necessary.343 Therefore, the Advisors recommend that the Council approve the MISO Cost
Recovery Rider as proposed by ENO;344 and
WHEREAS, the Council approves the combined MISO Cost Recovery Rider as proposed
by ENO; and

339

Id., citing Ex. No. ENO-55 at 31-32.
Id. at 101, citing Ex. No. ADV-1 at 29:10-15.
341
Id., citing Ex. No. ENO-41 at 40:23-41:3.
342
Id., citing Ex. No. ADV-1 at 29:18-19 and 30:13-14.
343
Id., citing Ex. No. ADV-1 at 3-13.
344
Id.
340

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 ELECTRIC RESIDENTIAL CUSTOMER CHARGE
WHEREAS, ENO’s proposes to increase the electric residential customer charge from the
current $8.07 to a proposed $15.53 customer charge.345 According to ENO, its cost of service
study showed customer-related costs of service per residential customer to be $21.07 a month.346
ENO witness Talkington stated that customer-related costs that do not vary with monthly changes
in a customer’s demand or energy usage should be recovered through a fixed monthly customer
charge. 347 ENO witness Thomas added that higher fixed charges relative to volumetric rate
structures provide more stability to ENO’s revenues;348 and
WHEREAS, AAE urges the Council to reject ENO’s proposal to nearly double the level
of the current residential customer charge and assert that a $15.53 customer charge is “extreme”
and fails to reflect the true nature of gradualism in utility ratemaking, as evidenced by national
trends in residential fixed charges;349 and
WHEREAS, Mr. Barnes asserted that ENO’s calculated customer unit cost is inflated by
including numerous costs that bear little or no relationship with costs (i) associated with connecting
a customer to the grid, or (ii) which vary directly with the number of customers being served.350
Barnes also charged that a higher customer charge would lower the volumetric kWh rate, thus
diluting customer incentives to use less energy;351 and

345

Ex. No. ENO-45 at 26.
Id.
347
Id. at 23.
348
Ex. No. ENO-2 at 62.
349
AAE/Sierra Club Initial Brief at 20.
350
Id.
351
Id. 15-19.
346

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 WHEREAS, AAE recommended a customer charge of $8.13/month, “in order to properly
reflect cost causation, avoid significant adverse impacts on customers with lower incomes, and
support the Council’s policies on energy efficiency;”352 and
WHEREAS, the Advisors’ recommended a $10 per month electric customer charge, which
is a relatively small increase that recognizes that costs have increased since the 2008 rate case but
also minimizes the impact on low-use customers.353 The Advisors expressed serious concern that
ENO’s proposed $15.21 electric customer charge is almost a 100% increase above the existing
customer charge, and that large change would have a substantial adverse impact on low-use
customers.354 Advisors’ witness Prep recommended a small increase in the residential customer
charge to moderate the bill impact on customers with lower or minimal usage.355 Mr. Prep further
testified that the remainder of that portion of the residential cost of service would be recovered
through kWh usage;356 and
WHEREAS, the Council shares the concerns expressed by AAE and the Advisors
regarding the impact of ENO’s proposed customer charge on low income and low use customers;
and
WHEREAS, the Council also finds that ENO’s proposal, which is an almost 100%
increase above the existing customer charge, fails to reflect the concept of gradualism in
ratemaking and is therefore, excessive; and
WHEREAS, the Council accepts AAE’s argument that an increase to the residential
customer charge would reduce customers’ incentives to use less energy. Such a result would be

352

AAE/Sierra Club Initial Brief at 31.
Ex. No. ADV-3 at 60.
354
Advisors’ Initial Brief at 62.
355
Ex. No. ADV-3 at 60.
356
Id.
353

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 inconsistent with the Council’s long-standing policy of supporting and increasing energy
efficiency in New Orleans; and
WHEREAS, the Council finds that not altering the Company’s current $8.07 customer
charge is consistent with addressing AAE’s and the Advisors’ concern regarding the potential for
significant adverse impacts on low income customers and supportive of the Council’s longstanding policy of supporting and increasing energy efficiency; and
WHEREAS, the Council rejects ENO’s proposed customer charge of $15.53 and finds
that the Company’s $8.07 customer charge shall remain unchanged as a result of the evidence
presented in this proceeding; and
AMI CUSTOMER CHARGE
WHEREAS, ENO proposes a customer charge for its costs in deploying and implementing
ENO’s Advanced Metering Initiative approved by the Council in Docket No. UD-16-04.
Specifically, ENO proposes an electric AMI charge and a gas AMI charge to be collected through
Rider AMICE and Rider AMICG, respectively; and
WHEREAS, ENO contends that the number of customers ENO serves, in large part, drives
the level of the costs associated with AMI. Therefore, these costs should be recovered through a
customer charge (rather than base rates) so that a customer bears only the cost that the customer
causes. The charges are intended to recover the net present value of the electric and gas AMI
revenue requirements. Any differences in the revenue resulting from the customer charges and the
actual costs of AMI would be reconciled through the proposed electric and gas FRPs. As proposed,
the charges are intended to recover the net present value of the electric and gas AMI revenue
requirements. Any differences in the revenue resulting from the customer charges and the actual
costs of AMI would be reconciled through the proposed electric and gas FRPs; and

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 WHEREAS, both the gas and the electric AMI charges would change annually, beginning
on January 1, 2020. The initial proposed monthly customer charges would be $2.95 for electric
customers and $0.60 for gas customers. In January of 2020, the proposed monthly customer
charges would be $3.67 for electric customers and $0.96 for gas customers; and
WHEREAS, after 2020, the gas AMI charge would decline annually until 2029 when it
terminates. Similarly, the electric AMI charge would decline annually until it terminates in
2035;357 and
WHEREAS, AAE argues that ENO’s proposed fixed monthly charge is unreasonable358
because AMI is not “typical” metering.359 AAE contends that “fixed customer charges should
recover the cost of connecting a customer to the grid.360 AAE argues that advanced metering and
the associated incremental costs above traditional meters are not strictly necessary for the customer
to be connected to the grid. 361 It also argues that a non-advanced meter and associated
infrastructure can do so at lower costs, but AMI is used for much more than measurement of a
customer’s consumption for billing purposes;”362 and
WHEREAS, instead AAE recommends the Council adopt a volumetric rate design in order
to support energy efficiency, protect the greater portion of lower income customers from
disproportionate impacts, and distribute the costs and benefits of AMI more equitably;363 and
WHEREAS, AAE further notes that a volumetric AMI charge would cause lower usage
customers to pay less towards AMI deployment, when those same customers act to reduce their
energy consumption or peak period demands, higher usage customers still receive a greater portion

357

Application at 37-38.
Ex. No. AAE-3 at 31-34.
359
Id. at 31.
360
AAE/Sierra Club Initial Brief at 42.
361
Id.
362
Ex. No. AAE-3 at 31.
363
Id. at 34.
358

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 of the benefits of the associated cost savings.364 Therefore, according to AAE, while higher usage
customers pay more under a volumetric design, they also receive more in return;365 and
WHEREAS, the Advisors contend that ENO’s proposed per-customer charges in Rider
AMICE and Rider AMICG are intended to allow ENO recover substantially all of its AMI-related
costs through these riders rather than base rates.366 The Advisors’ proposed allocation of AMI
cost responsibility is based on the net benefits identified in AMI Docket No. UD-16-04 including
“greater grid resiliency in the distribution network, improved outage and reliability performance,
improved grid planning for modifications and improvements, DSM programs, time differentiated
pricing, and specially designed customer options, among other system and customer benefits.”367
The Advisors also assert that ENO’s proposed allocation of cost responsibility for AMI-related
costs on a per-customer basis through a rider is inappropriate single-issue ratemaking. 368
Specifically, because the pace of AMI deployment is known, measurable, and reasonably within
ENO’s control and related costs are similarly known and measurable, the use of a rider is
unnecessary and singling-out AMI costs for recovery through riders constitutes inappropriate
single-issue ratemaking. 369 Accordingly, the Advisors recommend the Council deny ENO’s
request for Rider AMICE and Rider AMICG; and
WHEREAS, CCPUG argues against the Advisors’ recommended methodology for
assigning responsibility among the rate classes for costs related to ENO’s AMI deployment.
CCPUG favors ENO’s proposed per-customer methodology and labels the Advisors’
recommended benefits-based allocation methodology base rate “socialization.”370 In contrast, the

364

Id.
Id.
366
Advisors Initial Brief at 94; citing Ex. No. ADV-6 at 83-84.
367
Advisors’ Reply Brief at 20.
368
Advisors Initial Brief at 94; citing Ex. No. ADV-6 at 83-84.
369
Id.
370
CCPUG Initial Brief at 78.
365

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 Advisors dispute that their recommendation is a form of cross-subsidization, asserting that it is
based on a careful analysis of resulting net-benefits.371 Moreover, the Advisors assert that the
ENO/CCPUG proposal to recover AMI-related costs on a per-customer basis is flawed because
ENO’s proposed allocation of AMI costs on the basis of numbers of customers weighs
disproportionately on residential customers.372 In addition, the ENO has long-asserted that AMI
is intended to provide many functions and benefits beyond those of existing meters that serve the
sole function of generating billing information.373 Thus, the Advisors correctly note that a percustomer allocation of AMI-related costs would result in cross-subsidization benefiting large and
industrial customers at the expense of residential and small commercial customers; and
WHEREAS, the Council agrees with the Advisors’ contention that the ENO/CCPUG
proposal would result in cross-subsidization benefiting large and industrial customers at the
expense of residential and small commercial customers and reject the ENO/CCPUG proposal to
recover AMI-related costs on a per-customer basis because as ENO has argued since its initial
proposal in Docket No. UD-16-04. AMI provides many functions and benefits beyond existing
meters’ sole function to generate billing information.57 As ENO has repeated made clear, the
approximately $80 million AMI capital investment is more than just new meters, as the benefits
of AMI include greater resiliency in the distribution network, improved outage and reliability
performance, improved grid planning for modifications and improvements, DSM programs, and
time differentiated pricing. Moreover, as noted above, ENO agrees that the Advisors’ proposed
prospective treatment of known and measurable costs and attendant revenue change would
mitigate the need for the proposed AMI Riders;374 and

371

Ex. No. ADV-3 at 28:10-12.
Id. at 28:10-19
373
Id. at 28:13-16.
374
Ex. No. ENO-3 at 9:3-7; ENO Reply Brief at 48.
372

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 FORMULA RATE PLANS
WHEREAS, ENO proposed electric and gas FRPs with an implementation date of 2020
and an initial term of three years that incorporates many features of the predecessor FRP approved
by the Council in Resolution No. R-09-136, including the basic structure that evaluates whether
the Company’s rates fall within a bandwidth around the authorized ROE (midpoint) established
by the Council, with annual evaluations that prospectively adjust rates to the midpoint;375 and
WHEREAS, ENO also proposed several categories of FRP changes - for the E-FRP: (1)
changes to the target Evaluation Period Cost of Equity (“EPCOE”) to incorporate the proposed
RIM Plan’s adjusted ROE formula; (2) changes to accommodate the Energy Smart Program;
(3) changes to implement the Decoupling Pilot Program (4) a new provision for an interim Rate
Adjustment for NOPS non-fuel revenue requirement; (5) a new provision for changes in income
tax rates; (6) a change to the “Extraordinary Cost Changes” provision related to the revenue trigger;
and (7) a new provision for Rider PPCACR Transitional Items; 376 and for the gas FRP:
(1) changing the filing date to April 30, with the initial rate adjustment to be effective for the first
billing cycle in September; (2) the treatment of changes in the tax rate; and (3) increasing the
revenue requirement impact trigger to the Extraordinary Cost Changes section from $750,000 in
the previous FRP to $1 million;377 and
WHEREAS, both of ENO’s FRPs, which are based largely on the FRP’s previously
approved by the Council, include, among others, the following features:


Use of the previous calendar year as the Evaluation Period (i.e., historic test year);



Use of the authorized ROE set in this proceeding as the target Evaluation Period
Cost of Equity (“EPCOE”);

375

Ex. No. ENO-55 at 20.
Ex. No. ENO-41 at 29:11-21.
377
Ex. No. ENO-55 at 21; Ex. No. ENO-41 at 48:15-22.
376

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 

A dead band of plus or minus 50 basis points centered on the EPCOE, in which
there would be no change in rates;



A formula that adjusts the FRP revenue level for the Evaluation Period to
prospectively earn the EPCOE, commonly referred to as “resetting to the
midpoint,” if the Earned Rate of Return on Equity (“EROE”) is above or below the
deadband;



A seventy-five day review period;



A specified dispute resolution procedure; and



A three-year term;378 and

WHEREAS, the use of an FRP mechanism and several aspects of ENO’s proposed FRP
mechanism are undisputed by the parties. The Council finds that the undisputed elements of the
FRP are reasonable and should be approved; and
WHEREAS, the following aspects of ENO’s proposed FRP mechanism are disputed by
the parties: (1) whether total utility operating revenues and costs should be included in the FRP
calculation; (2) whether forward-looking adjustments for known and measurable changes in the
rate effective period should be included in the FRP calculation; (3) whether ENO’s proposed RIM
should be included in the FRP; (4) whether ENO should update the inputs to the class cost of
service studies in the E-FRP decoupling adjustment and how rates are reset if ROE is outside the
FRP bandwidth; and (5) whether and how costs related to NOPS should be included in the FRP
mechanism; and
(1)

Whether Total Utility Operating Revenues and Costs Should Be Included in the
FRP Mechanism

WHEREAS, the Advisors recommend that the Council should evaluate whether ENO is
under-earning or overearning in the FRP by evaluating the total utility cost of service, including

378

Ex. No. ENO-41 at 28:14-29:7; Ex No. ENO-3 at 7:3-20.

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 total ENO revenues and expenses, rather than limiting the FRP evaluation to base rate costs and
revenues. That approach to evaluating total utility revenue requirements is consistent with the
Advisors’ approach establishing a fully allocated cost of service; and
WHEREAS, the Advisors concur with ENO’s proposals to exclude Energy Smart costs,
Lost Contributions to Fixed Costs (“LCFC”), and the utility incentive from the E-FRP
mechanism, 379 and with ENO’s proposed provisions regarding (i) the effect of any tax rate
changes, (ii) increasing the revenue requirement trigger in the Extraordinary Cost Changes Section
from $2 million to $6 million, and (iii) realigning future purchase power capacity recovered in the
Advisors’ proposed PPCR to the E-FRP;380 and
WHEREAS, ENO opposes the inclusion of all revenues and expenses, including riders, in
the Electric and Gas FRPs, similar to its approach in the Application to use a cost of service limited
to base rates. ENO argues that no evidence has been offered to show that any other regulator in
the country requires utilities to include rider revenues and costs recovered through those riders
when setting base rates.381 ENO argues that the Advisors’ proposed method would not change the
level of ENO’s base revenue requirement to be recovered in base rates, would not give the Council
a better understanding of ENO’s financial performance, and could have the effect of shifting cost
responsibility among the rate classes, although ENO’s base revenue requirement from a total
Company perspective would be unaffected;382 and
WHEREAS, Air Products also opposes the Advisors’ proposal to include total revenues
and expenses in FRP evaluations, arguing that Riders should not be included because they have

Ex. No. ADV-3 at 76:3-4; Advisors’ Initial Brief at 105.
Ex. No. ADV-3 at 76:14-17; Advisors’ Initial Brief at 105.
381
ENO Initial Brief at 102.
382
Id.
379
380

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 nothing to do with whether ENO is under-earning or over-earning.383 Air Products believes a
distortion is created: “…by including FAC revenues in the base revenue requirement used to adjust
revenues after an FRP review has been conducted, then fuel revenues that recover cost that have
made no contribution to the under- or over recovery will be part of the factor used to apportion
any revenue changes, which will produce a distorted result;”384 and
WHEREAS, the Advisors argue that to avoid single issue ratemaking, the total cost of
service should be examined to adjust total revenues, not just to set base rates. 385 The Advisors
argue that ENO’s arguments are without merit, that base revenue requirement is only a portion of
the total cost of service; the Council should evaluate ENO’s financial performance and earned
ROE based on its total cost of service; and a “shift” in cost responsibility is meaningless when the
evaluation does not consider total costs. Moreover, the Advisors argue that decisions regarding
cost recovery mechanisms, such as base rates and riders, follow the evaluation of the utility’s total
revenue requirement, therefore, no distortion is created. 386 Under the Advisors’ proposal,
allocations of fixed costs and variable costs and the cost responsibility supporting customer class
revenue requirements are determined separately such that fuel costs and FAC revenues would not
distort the fixed costs revenue requirement; and
WHEREAS, the Advisors argue that in an FRP filing, a comprehensive evaluation of the
earned ROE compared to the Council-approved ROE requires that all costs and revenues be
included.387 The Advisors also argue that, contrary to the assertion of ENO that there would be
double-counting of cost and revenues, as long as all costs and revenues are supported by the

Air Products’ Initial Brief at 32.
Id. at 26. (Emphasis added.)
385
Advisors’ Reply Brief at 32.
386
Id. at 34.
387
Ex. No. ADV-5 at 23:11-13; Advisors’ Initial Brief at 107; Advisors’ Reply Brief at 34.
383
384

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 financial reports of the system accounts, and each program adjustment is supported with
explanation and workpapers, double-counting of costs and revenues should be avoided. 388 In
addition, the Advisors argue, Directive 6 of Resolution No. R-16-03 requires that all utility fixed
costs should be included in the decoupling revenue adjustment, regardless of the revenue recovery
mechanism used to recover any specific fixed (non-fuel) costs;389 and
WHEREAS, the Council finds that in an FRP filing, a comprehensive evaluation of the
earned ROE compared to the Council-approved ROE requires that all costs and revenues be
included; and
(2)

Whether Forward-Looking Adjustments for Known and Measurable Changes
Should be Included in the FRP Calculation

WHEREAS, the Advisors also recommend an additional provision under FRP Attachment
C, Evaluation Period Adjustments, paragraph 8. Other that would state: “ENO may propose other
known and measurable costs that are supportable and expected to be incurred in the prospective
12 months following the FRP Evaluation Period;”390 and
WHEREAS, the Advisors also recommend that the FRP provision for an extraordinary
cost change should be included as a proforma adjustment prospective to the FRP Evaluation Period
pursuant to the Advisors’ proposed revision to Attachment C, Adjustments paragraph 8, if such
occurs during the period.391 Otherwise, the extraordinary costs may be considered for interim
recovery, and included in the ROE bandwidth evaluation of the next FRP;392 and
WHEREAS, ENO agreed with the Advisors’ position that incorporating forward-looking
proforma adjustments to account for known and measurable costs (and attendant revenue changes)

Ex. No. ADV-5 at 24:1-6; Advisors’ Initial Brief at 107; Advisors’ Reply Brief at 34.
Ex. No. ADV-5 at 24:6-9; Advisors’ Initial Brief at 108; Advisors’ Reply Brief at 34.
390
Ex. No. ADV-3 at 78:9-13; Advisors’ Initial Brief at 106; Advisors’ Reply Brief at 35.
391
Ex. No. ADV-3 at 77:16-20; Advisors’ Initial Brief at 106; Advisors’ Reply Brief at 35.
392
Ex. No. ADV-3 at 77:20-21; Advisors’ Initial Brief at 106; Advisors’ Reply Brief at 35.
388
389

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 in the calendar year following the FRP evaluation period in a properly structured FRP would
address ENO’s concerns regarding regulatory lag to a great degree. 393 ENO also agreed that the
Advisors’ proposed prospective treatment of known and measurable costs and attendant revenue
change would mitigate the need for the Electric and Gas AMI Charge Rider and the DGM Rider,
although ENO witness Thomas argued for a provision to implement those riders in the event the
FRP terminates after the initial three-year term;394 and
WHEREAS, CCPUG opposes the Advisors’ proposal to include projected costs in the
FRP, arguing that the inclusion of projected costs – which may or may not ever be incurred –
undermines a utility’s incentive to operate effectively and economically. 395 CCPUG argues that
allowing ENO to include a “wish list” of investments it may make in the coming year in its current
rates is fraught with peril and ripe for abuse.396
WHEREAS, the Advisors argue that CCPUG ignores the requirement that projected costs
be “known and measurable.” 397 The Advisors contemplate that in order to be known and
measurable,398 such costs either (i) would have already been presented to and approved by the
Council prior to inclusion in an open and transparent proceeding that allows for public
participation, such as ENO’s projected AMI costs, or (ii) that such costs would be clearly supported
in ENO’s detailed budgeting process.399 The Advisors argue that their proposal is by no means a
blank check for ENO to simply include projected costs it would like to incur for projects that have
not been reviewed and approved by the Council in a proceeding that allows all interested parties

393

Ex. No. ENO-3 at 8:9-12; Ex. No. ENO-4 at 13:21-23; ENO Reply Brief at 48.
Ex. No. ENO-3 at 9:3-7; ENO Reply Brief at 48.
395
CCPUG Initial Brief at 69; CCPUG Reply Brief at 34.
396
Id.
397
Advisors’ Reply Brief at 35.
398
“Known and measurable” is discussed in the following testimony in this docket: Ex. No. ENO-41 at 2; Ex. No.
CCPUG-2 at 9; Ex. No. ADV-1 at 2; Ex. No. ADV-2 at 11; and Ex. No. ENO-40 at 18.
399
Ex. No. ADV-6 at 66:4-6; Advisors’ Reply Brief at 35-36.
394

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 to have input.400 As such, the Advisors recommend that the Council review such out-of-period
proforma adjustments to ensure they were indeed accomplished.401 The Advisors explain that if
ENO were shown to have abused this ratemaking treatment, the Council could then take
appropriate action.402 Thus, the Advisors argue, the concerns raised by CCPUG that ENO will be
able to collect a return on a “wish list” of investments that are never made are unfounded.403 The
Advisors recognize that ENO is undertaking a significant level of investment in its system and that
regulatory lag could be a sufficient obstacle and believe that this proposal will sufficiently mitigate
the impact of regulatory lag, without the need for unnecessary riders, while still providing ENO
an incentive to be efficient and allowing the Council oversight of ENO’s investments;404 and
WHEREAS, ENO argues that CCPUG’s assertion that new measures are unnecessary
because traditional FRPs provide near real-time recovery of costs actually incurred is supported
only by a vague conclusory statement in testimony that traditional FRPs eliminate much of the
regulatory lag without any analysis to clarify what this statement means.405 By way of contrast,
ENO argues, its own witness provided an analysis showing the cash flow effects of recovering a
large, long-term capital project with multiple plant closings throughout the year;406 and
WHEREAS, CCPUG witness Kollen argues that if the Council approves an E-FRP and/or
GFRP implementation date of 2020 based on a calendar year 2019 Evaluation Period, it should
require ENO to exclude all proforma adjustments for 2019.407 If such proforma adjustments are

Advisors’ Reply Brief at 36.
Id.
402
Id.
403
Id.
404
Id.
405
ENO Reply Brief at 48.
406
Id. at 48-49.
407
Ex. No. CCPUG-1 at 45:12-14; 51:12-26; Ex. No. CCPUG-2 at 25:1-7.
400
401

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 not excluded for 2019, then CCPUG objects to an E-FRP implementation date of 2020 and
recommends that it be delayed until 2021;408 and
WHEREAS, ENO disagrees with the suggestion of CCPUG witness Kollen that the
proposed FRPs should not use calendar year 2019 as the first evaluation period. ENO argues that
to use 2019 as the first evaluation period would be consistent both with prior Council practice and
LPSC practice;409 and
WHEREAS, the Council finds that an electric and gas FRP should be implemented for a
three-year period with an appropriate ROE and a bandwidth of +/- 50 basis points, to begin with a
May 2020 filing covering a calendar year 2019 test year; and
WHEREAS, the Council finds that ENO may propose other known and measurable costs
that are supportable and expected to be incurred in the prospective 12 months following the FRP
Evaluation Period, during which the FRP rate adjustment would be effective and that an
extraordinary cost change should be included as a proforma adjustment prospective to the FRP
Evaluation Period, or be considered for interim recovery and included in the ROE bandwidth
evaluation of the next FRP; and
(3)

Whether ENO’s Proposed RIM Should Be Included in the FRP

WHEREAS, ENO proposes a RIM within its electric FRP. ENO states that it is proposing
its RIM Plan because it recognizes that its reliability performance has not met the expectations of
ENO, its customers, and the Council.410 ENO’s intention is to align the earnings component of its
base rates to its distribution reliability performance.411 ENO proposes that its electric ROE (which
ENO proposes to be 10.75%) would be reduced by 25 basis points (to 10.5%) then, if ENO’s

408

Ex. No. CPPUG-1 at 45:14-15.
Ex. No. ENO-3 at 12:12-20, citing Resolution Nos. R-03-272 and R-09-136; ENO Reply Brief at 51-52.
410
Ex. No. ENO-1 at 23:3-6.
411
Id. at 23:11-12.
409

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 performance improves, as measured through ENO’s Distribution System Average Interruption
Frequency Index (“SAIFI”), it would return to the baseline ROE (10.5%) and thereafter ENO’s
SAIFI based on the Evaluation Period data would then translate into a number of positive or
negative basis points (maximum of 25) to be added to the baseline ROE. 412 ENO states that its
expected year-end 2018 SAIFI score is expected to be 1.65.413 ENO proposes that if its SAIFI
improves to 1.24 the adjustment would be zero, a score of 1.40 or worse would warrant a 25 basis
point decrease from 10.75%, and an improvement to 1.05 would warrant a 25 basis point increase
from 10.75%.414 ENO argues that this proposal directly addresses the reliability issue, balances
the interests of stakeholders, is transparent, and is administratively straightforward to
implement;415 and
WHEREAS, CCPUG argues that the proposed RIM should be rejected by the Council.416
CCPUG argues that given ENO’s unacceptably poor electric system reliability over the last few
years, the Council should not under any circumstances approve a regulatory incentive mechanism
that provides the possibility of ENO earning a higher ROE for improved system reliability.417
CCPUG argues that reliable service is part and parcel of every utility company’s duty, including
ENO, under the Regulatory Compact.418 In other words, in return for its monopoly status and the
absence of competition, its power of eminent domain, and the opportunity to earn an almost
guaranteed ROR, the utility’s service must be reliable. 419 CCPUG also argues that ENO has
admitted that it does not require an incentive to provide reliable service.420 CCPUG argues that

412

Id. at 24:1-26:2.
Id. at 28:5-6.
414
Id. at 28:3-16; Ex. No. ENO-41 at 31:2-23.
415
Id. at 26:5-19.
416
Ex. No. CCPUG-3 at 50:7-8.
417
Ex. No. CCPUG-1 at 50:10-13.
418
Id. at 50:13-14; CCPUG Reply Brief at 36.
419
Ex. No. CPPUG-1 at 50:14-17.
420
CCPUG Reply Brief at 36, quoting City Council Hearing Transcript, 122:2-8 (June 18, 2019).
413

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 the Council should set base level performance attainment levels in this proceeding of 1.16 for
SAIFI and 113.8 for SAIDI. 421 CCPUG suggests a 25 basis point reduction penalty for
underperformance and no incentive for improved performance;422 and
WHEREAS, Air Products also opposes the RIM, arguing that the mechanism is
conceptually flawed because it would reward ENO for doing what it is supposed to be doing in the
first place -- namely, providing reliable service.423 Air Products urges the Council to reject the
proposed RIM, or, in the alternative that the RIM should not apply to customers who take service
at the transmission level;424 and
WHEREAS, the Advisors argue that as a public service company, ENO should prudently
manage its electric utility, including making prudent expenditures and investments, and SAIFI is
one metric for ENO’s performance.425 They argue ENO should not require an incentive to act
prudently and achieve reasonable results for stakeholders.426 The Advisors also argue that even if
the Council were to decide to incentivize ENO to improve its reliability, the Advisors would not
recommend the Council utilize an ROE adjustment to do so;427 and
WHEREAS, the Advisors argue that there is not a direct relationship between ROE and
distribution system performance and the ROE customarily affects ENO’s return on all its
investments, not just the investments in the distribution plant that is generally regarded as most
closely related to many of ENO’s reported service outages, which constitutes only 57.9% of ENO’s
net plant in service. 428 Moreover, they argue, the Council is currently investigating ENO’s

421

Ex. No. CCPUG-3 at 52:20-23.
Id. at 52:14-18 and 53:2-5.
423
Ex. No. AP-3 at 20:14-16; Air Products’ Initial Brief at 36; Air Products’ Reply Brief at 13-14.
424
Ex. No. AP-2 at 21:5; Air Products’ Initial Brief at 36; Air Products’ Reply Brief at 14.
425
Ex. No. ADV-1 at 15:2-4; Advisors’ Initial Brief at 110.
426
Ex. No. ADV-1 at 15:4-5; Advisors’ Initial Brief at 110.
427
Advisors’ Initial Brief at 110.
428
Ex. No. ADV-1 at 15:9-14; Advisors’ Initial Brief at 110-111.
422

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 reliability performance in Council Docket No. UD-17-04, including consideration of what
appropriate SAIFI and SAIDI standards should be as well as any appropriate incentives and
penalty mechanisms related to those standards.429 The Advisors argue that setting a target SAIFI
level and incentive mechanism in this proceeding would be premature prior to the conclusion of
the investigations being conducted in Docket No. UD-17-04.430 Additionally, the Advisors note,
the impacts on ratepayers of the proposed RIM are not insignificant. Under ENO’s proposed RIM,
they argue, if ENO were to succeed in improving its SAIFI performance sufficiently to allow its
ROE to increase from 10.5% to 11.0%, the result would be that ENO is able to collect an additional
approximately $2.7 million from its ratepayers.431 The Advisors recommend that the Council not
approve ENO’s proposed RIM; and
WHEREAS, in response to the Advisors’ argument that any minimum reliability standard
should be addressed in Council Docket No. UD-17-04, ENO responds that it would be amenable
to the Council setting ENO’s electric ROE at 10.50% in this proceeding and directing the details
of a balanced financial incentive and penalty mechanism that would permit ENO’s ROE to adjust
above 10.50% be determined in Docket No. UD-17-04, which ENO anticipates would be resolved
prior to the resetting of rates through the FRP;432 and
WHEREAS, the Advisors argue that there is no need to consider ENO’s proposed RIM
further in Docket No. UD-17-04.433 They argue that ENO’s appropriate allowed-ROE will be
established in this rate case, and the Council is considering whether or not to adopt minimum
reliability performance standards in Docket No. UD-17-04.434 The Advisors take the position that

429

Resolution No. R-17-427.
Ex. No. ADV-1 at 16:10-17:2; Advisors’ Initial Brief at 111.
431
Ex. No. ADV-1 at 14:18-20; Ex. No. ADV-6 at 12:3-11; Advisors’ Initial Brief at 111.
432
Ex. No. ENO-3 at 19:20-20:3.
433
Ex. No. ADV-2 at 4:11-15; Advisors’ Initial Brief at 111.
434
Ex. No. ADV-2 at 4:6-8; Advisors’ Initial Brief at 111-112.
430

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 there is no need to consider ROE and minimum reliability performance standards in conjunction
with each other,435 because there simply is no direct relationship between the utility’s ROE and
distribution performance -- any adjustment to ROE would typically affect ENO’s return on all of
its plant, not just the distribution plant that is generally regarded as most closely related to many
of ENO’s reported service outages;436 and
WHEREAS, ENO argues that its proposed RIM Plan is a transparent and straightforward
approach towards achievement of certain reliability performance goals, making the earnings
component of its rates contingent upon reliability performance.437 ENO argues that a mechanism
tying reliability performance to any financial outcome should be symmetrical and that if a financial
value (i.e. penalty) can be ascribed to performance below the range, then a value exists for
performance above the range. 438

ENO also argues that similar mechanisms have been

implemented by regulators in other jurisdictions.439 ENO writes:
Reliable service is ENO’s goal, but providing reliable service comes at a cost; the
question becomes what is the appropriate balance between the two. This is a
tradeoff that regulators must factor into their decision-making on just and
reasonable rates;440
and
WHEREAS, the Advisors argue that while ENO is correct that it is the job of the regulator
to determine the point at which the incremental gains to be achieved by further increasing
reliability are outweighed by the cost of doing so, reliable service is not merely a “goal” of the
utility, rather, it is the fundamental purpose for which the utility exists.441 They argue that ENO’s

Ex. No. ADV-2. at 4:8-9; Advisors’ Initial Brief at 112.
Ex. No. ADV-2 at 4:9-5:4; Advisors’ Initial Brief at 112.
437
ENO Initial Brief at 52.
438
Id. at 53.
439
Id. at 52.
440
Id. at 54-55.
441
Advisors’ Reply Brief at 37.
435
436

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 attempt to extract further profit from ratepayers for merely improving its reliability to an acceptable
level is distasteful at best. 442 The Advisors take the position that when coupled with ENO’s
proposal to change Section 11 Continuity of Service of ENO’s Service Regulations, 443 and ENO
witness Stewart’s statement on the stand that she would not say ENO has a duty to provide safe
and reliable electric service,444 these arguments demonstrate a troubling attitude on ENO’s part
that reliability is somehow optional and the utility must be provided with an incentive to provide
it;445 and
WHEREAS, the Advisors oppose ENO’s RIM proposal to tie its ROE to its reliability
performance arguing that ENO’s earnings component of its rates should not be contingent upon
its reliability performance. They argue that the Council is not faced with a “tradeoff” and is not
required to provide ENO with an incentive to increase reliability just because reliability comes
with a cost, all of which will be recovered from ratepayers in any event;446 and
WHEREAS, Air Products urges the Council to reject the proposed RIM, or in the
alternative, to find that the mechanism should not be applied to transmission-level customers such
as Air Products. 447 Air Products argues that its witness, Brubaker, testified that the RIM
mechanism is conceptually flawed because it would reward ENO for doing what it is supposed to
be doing in the first place -- namely, providing reliable service.448 In apparent agreement with the
Advisors testimony,449 Air Products also notes that ENO is proposing, through its Distribution
Grid Modernization Rider, to charge customers for the cost of upgrading its distribution grid,

442

Id.
Ex. No. ENO-6, at Ex. No. MPS-8 at 18.
444
City Council Hearing Transcript, 114:17-18 (June 18, 2019).
445
Advisors’ Reply Brief at 37.
446
Id. at 38.
447
Air Products’ Initial Brief at 35.
448
Id.; Ex. No. AP-3 at 20:16-21:3.
449
Ex. No. ADV-1 at 15:10-19.
443

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 which would in turn be expected to improve reliability -- thus, customers (not ENO shareholders)
would have already paid for the improved reliability of ENO’s distribution system.450 Air Products
also argues that to the extent the Council approves the RIM plan, it should not apply to customers
who take service at the transmission level because they will not benefit from improvements in
reliability on the distribution system since the entire focus of reliability improvement is at the
distribution level;451 and
WHEREAS, AAE and Sierra Club also oppose the RIM Plan, noting that ENO fails to
even recognize its responsibility to provide reliable service to New Orleans ratepayers, and that
ENO is effectively asking to be rewarded for operating its distribution system in the manner to
which ratepayers are entitled, but have not been receiving for years.452 AAE and Sierra Club argue
that the Council should reject ENO’s attempt to “do an end run” around the Council’s ongoing
investigation in UD-17-04. 453 In agreement with Advisors’ testimony, 454 they also argue that
ENO’s ROE affects its return on all investments, not just the distribution plant that is most closely
related to many of ENO’s reported service outages, and ROE is based on market performance of
proxy companies, not SAIFI values, so the ROE is not the best mechanism to incentivize ENO’s
distribution-related performance given its broad impact on ENO’s overall rates.455 AAE and Sierra
Club also allege that ENO has been overearning on its ROE for a number of years, and during that
period had a dismal record regarding distribution system outages, so there is no reason to believe
that allowing ENO to over-earn is the best way to incentivize the Company.456 Finally, they note
that FERC has declined incentives to utilities “for doing what it is supposed to do, i.e., to
Air Products’ Initial Brief at 35; Ex. No. AP-3 at 21:9-11.
Air Products’ Initial Brief at 35; Ex. No. AP-3 at 21:11-13 and 22:3-4.
452
AAE/Sierra Club Initial Brief at 46-47.
453
Id. at 48.
454
Ex. No. ADV-1 at 15:10-19.
455
Id.
456
Id.
450
451

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 adequately maintain its facilities in a prudent cost-effective manner,” and argue that New Orleans
ratepayers should not be required to pay extra for a service they are entitled to by virtue of ENO’s
status as the monopoly provider of electric service;457 and
WHEREAS, the Council finds that ENO’s proposed RIM Plan should be denied, and the
issue of reliability standards and any penalties for failing to meet them should be taken up in
Council Docket No. UD-17-04 rather than in this rate case; and
(4)

Whether ENO Should Update the Inputs to the Class Cost of Service Studies in the
E-FRP Decoupling Mechanism, and How Rates are Reset if ROE is Outside the
FRP Bandwidth

WHEREAS, the Advisors argue that the electric FRP decoupling revenue adjustment for
each customer class should be determined by comparing the evaluation period fixed & variable
revenue by class with the FRP evaluation period allocation of total ENO fixed and variable revenue
requirement;458 and
WHEREAS, Air Products also opposes the Advisors’ proposal that whenever an E-FRP
evaluation is conducted, the external allocation factors be updated, arguing that this would make
the process unnecessarily complex, expensive, contentious and inefficient and would not prevent
significant changes in rates for customers in rate classes with only a few customers as a result of
decoupling;459 and
WHEREAS, the Advisors explain that after determining the allocated (fixed and variable)
cost responsibility from the total cost of service, the E-FRP adjustment by customer class can be
determined by the difference between the evaluated customer class total cost of service and the

Id. at 48-49, quoting New England Power Pool, 97 FERC ¶ 61,093 at 61,477 (2001); order on reh’g, 98 FERC
¶ 61, 249 (2002), AAE/Sierra Club Reply Brief at 19.
458
Ex. No. ADV-3 at 78:6-8.
459
Ex. No. AP-4 at 12:3-11; Air Products’ Reply Brief at 22-23.
457

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 customer class actual total revenue and there would be no issue of double recovery. 460 The
Advisors argue that updating external allocation factors with current billing determinants is not
complex and reflects changes in customer usage necessary to maintain fairness in the customer
class decoupling revenue adjustments; and
WHEREAS, the Council agrees with the Advisors that the E-FRP decoupling revenue
adjustment for each customer class should be determined by comparing the evaluation period fixed
and variable revenue by class with the FRP evaluation period allocation of total ENO fixed and
variable revenue requirement; and
WHEREAS, the Advisors recommend that the Council approve a three-year FRP with an
appropriate ROE and a bandwidth of +/- 50 basis points, 461 to begin with a May 2020 filing
covering a calendar year 2019 test year;462 and
WHEREAS, Air Products opposes an FRP adjustment resetting rates to EPCOE463 (the
midpoint of the ROE bandwidth), but rather proposes that if the earned ROE (“EROE”) is above
the upper bandwidth, the revenue adjustment be only partially moved toward the upper bandwidth
(60% of the way toward the upper bandwidth), such that ENO is able to retain some of the benefits
of the efficiencies it gained.464 When earnings are below the lower edge of the bandwidth, Air
Products recommends that the adjustment be 60% of the way toward the lower bandwidth;465 and
WHEREAS, ENO opposes this proposal and disagrees arguing that such a mechanism
would result in ENO not having an opportunity to recover its costs and would always result in rate

460

Ex. No. ADV-3 at 24:9-12.
Id. at 77:8-9.
462
Id. at 77:9-11.
463
Ex. No. AP-3 at 22:13-14.
464
Id. at 23:13-21.
465
Id. at 24:8-11.
461

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 adjustments that set rates at a level below ENO’s revenue requirement and provide ENO no
opportunity to recover its costs;466 and
WHEREAS, the Advisors oppose Air Products’ proposal and support the complete reset
of rates when the earned ROE falls outside the bandwidth.467 The bandwidth is set at a reasonable
range to allow ENO to keep a reasonable amount of value from efficiencies while protecting ENO
against incurring too much risk from investing in and/or supporting and promoting energy
efficiency, demand response, rooftop solar and the like.468 Not allowing rates to be reset when
they fall below the bandwidth would give ENO an incentive to oppose those programs, and
allowing ENO to keep more of the profits of above-bandwidth revenues would provide ENO with
too much incentive to increase kWh sales rather than to promote conservation;469 and
WHEREAS, the Council agrees with the Advisors’ assessment of Air Products’ proposal
and finds it should be rejected; and
(5)

Whether and How Costs Related to NOPS Should Be Included in the FRP
Mechanism

WHEREAS, ENO proposes to begin recovering the estimated first year revenue
requirement associated with the NOPS in the first billing cycle of the month after the NOPS enters
commercial operation.470 ENO testified that it expects the NOPS to enter commercial operation
in January 2020,471 although that date has since been moved later into year 2020; and
WHEREAS, ENO also proposes to recover the estimate through an interim rate adjustment
under ENO’s proposed E-FRP.472 Assuming that the Council approves an E-FRP, the Company

466

ENO Reply Brief at 52.
Advisors’ Reply Brief at 40.
468
Id.
469
Id.
470
Ex. No. ENO-2 at 67:11-13 (HSPM).
471
Id. at 67:13-14 (HSPM).
472
Id. at 67:18-19 (HSPM).
467

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 requests that the Council confirm in this proceeding that an interim rate adjustment under ENO’s
proposed E-FRP is the contemporaneous cost recovery mechanism to be used to recover the NOPS
first year revenue requirement;473 and
WHEREAS, CCPUG argues that it is reasonable to include an interim rate adjustment in
the E-FRP to recover the costs of NOPS, but that the costs included in the calculation of the interim
rate adjustment are not reasonable for three reasons.474 First, ENO’s ROE is excessive – (ENO’s
proposed 10.5% ROE should be replaced by CCPUG proposed 9.35% ROE or whatever other
ROE the Council authorizes.475 Second, the NOPS depreciation rate and depreciation expense are
excessive, and should be based on a CCPUG proposed service life of 50 years, instead of the
Company’s assumed service life of 30 years. 476 The third reason the costs included in the
calculation of the interim adjustment are unreasonable is that CCPUG believes that ENO intends
to maintain the NOPS first year revenue requirement until the next general rate case, with no
revenue requirement reduction due to greater accumulated depreciation and ADIT;477 and
WHEREAS, in Council Docket No. UD-16-02, in which the Council approved NOPS, the
Advisors proposed that the cost recovery of the NOPS investment be accomplished
contemporaneously as a second step rate adjustment subsequent to the 2019 effective date of the
revised rates from the instant docket.478 Specifically, the Advisors believe that the NOPS interim
rate adjustment could be a provision in the proposed FRP, providing contemporaneous recovery
from the date of NOPS commercial operation (“COD”). 479 The Advisors have proposed that
proforma adjustments be included in the FRP for the 12-month period subsequent to the FRP

473

Id. at 67:20-23 (HSPM).
Ex. No. CCPUG-1 at 46:8-11.
475
Id. at 46:13-20.
476
Id. at 47:1-19.
477
Id. at 47:20-48:4.
478
Resolution No. R-18-65 at 176.
479
Advisors’ Initial Brief at 44.
474

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 evaluation period, which would encompass calendar year 2020 for the first FRP.480 According to
the Company, NOPS is expected to enter commercial operation in early 2020.481 The Advisors
argue that if the NOPS updated revenue requirement filing is not included as a prospective
proforma adjustment in the proposed FRP filed in April 2020, the NOPS in-service rate
adjustment, beginning with the month following COD, would be effective until NOPS costs are
included in the ROE bandwidth evaluation of the following FRP.482 If the NOPS updated revenue
requirement filing is included as a 2020 proforma adjustment in the proposed FRP filed in April
2020, the NOPS in-service rate adjustment would be effective with the COD until the FRP rate
adjustment is implemented in September 2020, at which time NOPS cost recovery would be
included in the FRP rate adjustment;483 and
WHEREAS, ENO objects to Advisors’ witness Prep’s approach. The Company asserts
that the potential exists that the bandwidth calculation may prevent ENO from recovering 100%
of the NOPS costs.484 ENO argues that “it would be illogical to permit 100% recovery of the
NOPS costs in the interim rate adjustment but later reduce that recovery because of the FRP
bandwidth mechanics.” 485

Therefore, the Company believes that the first-year revenue

requirement should be reflected in its entirety in the FRP Rate Adjustment and any subsequent
cost changes be subject to the bandwidth calculation;486 and
WHEREAS, the Advisors urge the Council to adopt witness Prep’s recommendation
regarding NOPS cost recovery and the inclusion of NOPS in the proposed FRP revenue

480

Ex. No. ADV-5 at 24:18-25:2.
Ex. No. ENO-2 at 67:13-14.
482
Ex. No. ADV-5 at 25:3-6.
483
Id. at 25:4-10.
484
Ex. No. ENO-3 at 48:5-6.
485
Id. at 48:6-8.
486
Id. at 48:8-10.
481

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 adjustment.487 The first-year revenue requirement associated with NOPS should be included in
rates as an in-service rate adjustment, beginning with the month after NOPS enters commercial
operation. The Advisors argue that this rate adjustment shall remain in place until NOPS costs are
included in the costs of an FRP evaluation period and in the ROE bandwidth calculation.488 The
Advisors disagree with ENO’s argument that it should be permitted to recover the initial year of
NOPS costs without being included in an ROE evaluation.489 As with all other costs included in
an FRP evaluation of earnings, ENO has the opportunity to earn its approved ROE rather than a
guarantee that it will recover 100% of NOPS costs;490 and
WHEREAS, the Advisors recommend that the interim Rate Adjustment for NOPS nonfuel revenue requirement be included under the proposed FRP Attachment C, paragraph 8, or in
the following FRP within the bandwidth evaluation, depending on the commercial operation date,
and that the FRP provision include an allocation of NOPS costs based on the rate case production
demand allocation factor, rather than total base rate costs;491 and
WHEREAS, CCPUG argues that ENO’s proposal will lead to excessive recovery in the
first year and every year thereafter until base rates are reset, because the ROR is excessive, the
depreciation rate and depreciation expense are excessive, and the revenue requirement is generally
at the maximum for the first year and then declines due to the accumulation of book depreciation
and the tax savings from accelerated tax depreciation;492 and
WHEREAS, CCPUG recommends ENO apply a 9.35% ROE to the E-FRP, that the first
year revenue requirement for NOPS be reduced to reflect a 50-year service life, and that ENO be

Advisors’ Initial Brief at 45.
Id. at 45.
489
Id.
490
Id.
491
Ex. No. ADV-3 at 77:12-16.
492
CCPUG Initial Brief at 68; Ex. No. CCPUG-1 at 46:8-48:4.
487
488

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 ordered to reduce the revenue requirement for NOPS each year to reflect an additional year of
depreciation and deferred income tax expense;493 and
WHEREAS, ENO suggested that the Council not determine the parameters for recovery
of the NOPS revenue requirement in this proceeding, but wait until ENO makes its proposed rate
filing prior to the in-service date of NOPS based on the estimated first NOPS revenue
requirement.494 CCPUG opposes this suggestion and argues that the Council should decide the
issue in this case;495 and
WHEREAS, AAE and Sierra Club oppose the NOPS adjustment in its entirety, arguing
that because a presiding judge in Civil District Court issued a bench ruling voiding Resolution No.
R-18-65, the construction of NOPS does not have the approval of the Council.496 As AAE and
Sierra Club are well aware, the Council appealed this ruling, and thus, that matter is not yet final.497
The Advisors propose that to the extent that the matter has not yet become final at the time that
the Council issues a resolution in this rate case, any NOPS adjustment approved by the Council
should be conditioned upon the construction of NOPS and associated costs having been approved
through a final judgment of the Council;498 and
WHEREAS, after considering all of the arguments and evidence related to this issue, the
Council agrees with the Advisors proposal that proforma adjustments should be included in the
FRP for the 12-month period subsequent to the FRP evaluation period, which would encompass
calendar year 2020 for the first FRP.499 The Council also finds that if the NOPS updated revenue
requirement is included as a prospective proforma adjustment in the bandwidth evaluation of the

493

CCPUG Initial Brief at 69; Ex. No. CCPUG-1 at 48:15-20.
Ex. No. ENO-3 at 48.
495
Ex. No. CCPUG-2 at 29:9-30:13.
496
AAE/Sierra Club Initial Brief at 53.
497
Advisors’ Reply Brief at 52.
498
Id.
499
Advisors’ Initial Brief at 43-44; Ex. No. ADV-5 at 24:18-25:2.
494

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 proposed E-FRP filed in April 2020, the NOPS in-service rate adjustment, beginning with the
month following COD, would be effective until NOPS cost recovery is included in the E-FRP
revenue adjustment of the first FRP. The Council further finds that if the NOPS updated revenue
requirement filing is not included as a prospective proforma adjustment in the proposed E-FRP
filed in April 2020, the NOPS in-service rate adjustment, beginning with the month following
COD, would be effective until NOPS costs are included in the ROE bandwidth evaluation of the
following E-FRP;500 and
WHEREAS, the Council finds that this course of action is consistent with the approach to
evaluate the total utility cost of service and avoid single issue ratemaking; and
WHEREAS, the Council finds it reasonable to avoid future uncertainty and additional
litigation costs by the parties not to defer consideration of the NOPS adjustment until a future date,
but rather, as the Advisors suggest, to approve a NOPS adjustment with an instruction to ENO that
no actual costs should be flowed through that adjustment to ratepayers until such time as the
construction of NOPS and the associated costs have been approved through a final judgment of
the Council; and
WHEREAS, the Council finds that the interim Rate Adjustment for NOPS non-fuel
revenue requirement be included under the proposed E-FRP Attachment C, paragraph 8, or in the
following E-FRP within the bandwidth evaluation, depending on the commercial operation date;
and
WHEREAS, the Council finds that the E-FRP provision should include an allocation of
NOPS costs based on the rate case production demand allocation factor, rather than total base rate
costs; and

500

Advisors’ Initial Brief at 44; Ex. No. ADV-5 at 25:3-6.

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 DECOUPLING
WHEREAS, the Advisors explain that in Resolution No. R-16-03, ENO was ordered to
include in its next base rate case filing a proposal for an electric utility full decoupling mechanism
as a three-year pilot program, to begin with the implementation of rate changes arising from the
Combined Rate Case; and
WHEREAS, the Advisors also argue that Resolution No. R-16-03 requires that all utility
fixed costs should be included in the decoupling revenue adjustment, regardless of the revenue
recovery mechanism used to recover any specific fixed (non-fuel) costs;501 and
WHEREAS, the Advisors argue that Resolution No. R-16-03 also requires (i) that the
fixed cost revenue requirement should be determined on an allocated basis for each customer class,
(ii) that the allocation methodology should be applied consistently on an annual basis to determine
the decoupling revenue adjustments by customer class, (iii) and that the fixed-cost customer rate
class allocation factor should be updated annually (with current billing determinants);502 and
WHEREAS, ENO proposes a Decoupling Pilot Program within the electric FRP, through
a four-step process to be applied only if a rate adjustment is necessary under the terms of the
rider.503 Under the decoupling proposal, the fixed and variable cost revenue requirements would
be recovered from each rate class consistent with the allocation methodology used in the baseline
rate case.504 In the first step, the Baseline Fixed Cost Revenue Requirement and the Variable Cost

501

Ex. No. ADV-5 at 24:6-9.
Id.
503
Ex. No. ENO-55 at 20-21; Ex. No. ENO-41 at 32:23-33:2.
504
Ex. No. ENO-55 at 21.
502

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 Revenue Requirement would be determined.505 The second step would be to allocate each Rate
Class’s Evaluation Period Base Revenue (and FRP Revenue, if any) between Fixed Revenue and
Variable Revenue using the Baseline Revenue Requirement. 506 The third step would be to
compute each rate class’s Evaluation Period Fixed and Variable Revenue Deficiency or Excess.507
The fourth and final step would be to calculate the Rate Adjustment for each rate class;508 and
WHEREAS, under ENO’s decoupling proposal, the revenue adjustments would be the
difference between actual E-FRP evaluation period customer class base rate revenues and the EFRP electric base rate revenue requirements allocated to customer classes using customer class
base rate revenues approved by the Council in the instant docket; and
WHEREAS, under ENO’s decoupling proposal, the E-FRP/decoupling base rate
adjustment for each rate class would be calculated from each rate class’s E-FRP evaluation period
fixed and variable base rate revenue deficiency or excess, and applied as a percent of base rate
revenue;509 and
WHEREAS, ENO’s decoupling proposal would not use cost allocation factors updated for
each E-FRP evaluation period, and assumes the proportions of customer class fixed and variable
base rate revenue requirements to be fixed (based on those values in the instant docket) for each
of the E-FRP evaluation periods;510 and
WHEREAS, AAE witness Morgan recommends four changes to ENO’s decoupling
proposal: (1) remove it from the effects of the FRP deadband; (2) clarify that it will only operate
on either (a) revenues from customer billing charge billing determinants or minimum bill

505

Ex. No. ENO-41 at 34:12-17.
Id. at 36:6-8.
507
Id. at 36:16-18.
508
Id. at 37:3-7.
509
Id. at 36:16-18; 37:3-7.
510
Ex. No. ENO-55 at 21; Ex. No. ENO-41 at 34:12-17.
506

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 requirements in tariffs; or (b) revenues collected under tariff riders that are subject to full
reconciliation; (3) clarify that the comparison is between the most recent approved revenues and
the actual revenues, allocated to rate class/schedules per approved allocation factors, and not to a
calculation of required allocated revenues that includes changes in costs during the decoupling
period and (4) authorize ENO to calculate the difference between actual and authorized throughbased revenues for fixed recovery on a monthly basis during any year, applying a Council-set
carrying charge rate evenly to balances owed customers and owed ENO;511 and
WHEREAS, AAE witness Morgan agrees that she did not participate in any of the
Council’s decoupling proceedings leading to the adoption of the Council’s decoupling resolution,
Resolution No. R-16-103. 512 She maintains, however, that decoupling should focus only on
revenues, not expense, and that revenue decoupling is always backward looking - a true-up for
what actually happened compared to what was expected to happen. 513 AAE argues that any
decoupling mechanism should operate separately from any FRP, be backward-looking in
reconciliation, remove the need for any LCFC and ensure that there are no gaps that could penalize
ENO for achieving the most energy efficiency it can;514 and
WHEREAS, the Advisors recommend that the full decoupling mechanism should be
approved for the three-year electric FRP term, that the total allocated costs of service for each
customer class should be included in the decoupling revenue adjustment, and that the customer
rate class allocation factors should be updated annually (with current billing determinants); 515 and

511

Ex. No. AAE-1 at 3:11-23; Ex. No. AAE-2 at 2:6-3:7, 9:16-21, 16:16-22; AAE Reply Brief at 16.
Ex. No. AAE-2 at 3:15-4:1.
513
Id. at 4:14-15 and 5:8-9; AAE Reply Brief at 16.
514
Ex. No. AAE-2 at 8:10-18.
515
Ex. No. ADV-3 at 80:1-4.
512

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 WHEREAS, the Advisors concur with ENO’s recommendation that a decoupling
adjustment be applied only if the E-FRP revenue adjustment is outside the bandwidth, 516 but
recommend that the decoupling revenue adjustment be applied consistently to all customer classes
based on the E-FRP evaluation period total revenue requirements of each customer class;517 and
WHEREAS, the Advisors propose the following steps: (i) the “baseline” customer class
revenue requirements in the instant Docket be updated with a new baseline of customer class fixed
and variable revenue requirements in the E-FRP; (ii) the E-FRP fixed and variable total revenue
requirements be determined for each customer class by an allocation of costs and a return
component based on the rates of return corresponding to the customer class revenues set in the
instant docket; (iii) the fixed and variable revenue deficiencies/excesses be determined for each
customer class by comparing the E-FRP customer class total revenue requirements with the
customer class evaluation period total revenues; and (iv) the customer class decoupling
adjustments be applied within each customer class with updated billing determinants excluding
the customer charge;518 and
WHEREAS, ENO argues that its proposed decoupling approach is the only decoupling
approach consistent with Resolution No. R-16-103 and accompanies by detailed explanatory
testimony, a complete rate schedule setting forth the decoupling approach with exhibits, and a
detailed example, and that no other party provided a proposal as comprehensive as ENO’s;519 and
WHEREAS, ENO argues (i) that the Advisors’ assignment of the different required
before-tax rates of return on rate base to each customer/rate class was done under no objective

516

Ex. No. ADV-3 at 79:3-4.
Id. at 79:4-7.
518
Id. at 79:9-11 and 78:6-8.
519
ENO Reply Brief at 94.
517

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 standard that can be replicated,520 and (ii) that the proposed revenue by rate class approved in this
proceeding be used to allocate ENO’s revenue requirement in future FRP evaluation reports
instead of developing customer/rate class revenue requirements from updated cost allocations and
customer/rate class rates of return;521 and
WHEREAS, ENO argues that there could be unintended consequences if a decoupling
mechanism were to include all customer classes, particularly classes with few customers. 522 The
Advisors argue, however, that concern of unintended consequences related to a customer class
with few customers is without merit because updating allocation factors and billing determinants
with each FRP will accommodate any shifts in customers and usage within these classes; and
WHEREAS, ENO also argues that it has significant concerns with the Advisors’ proposal
that the decoupling adjustment be performed by applying the same allocation methodology
approved in this proceeding, and that ENO provide a new COS Study each year by updating the
allocation factors for each customer class with then-current customer data.523 ENO argues that it
would substantially undermine the purposes and efficiencies of an FRP and there would be
minimal benefit to be gained from developing updated allocation factors and presenting a fully
developed COS Study each year. 524 ENO also argues that the Advisors’ proposal would
substantially undermine the purposes and efficiencies of an FRP by creating an inefficient use of
resources and significant additional work.525 ENO argues that FRP’s streamline the rate setting
process by eliminating the usual contentious debate around the allocation of the revenue
requirement to the various rate classes and the rate design for three to five years, which is allowed

520

Ex. No. ENO-42 at 20:6-21:9, see also, ENO Reply Brief at 94.
Ex. No. ENO-42 at 22:3-4.
522
Ex. No. ENO-13 at 2:8-15 and 4:11-13.
523
Ex. No. ENO-42 at 14:16-15:3.
524
Id. at 15:3-6.
525
Id. at 15:3-20.
521

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 because, typically, there are no substantial changes in operations from year to year that would
materially affect cost allocations among customer classes.526 ENO argues that it will be very labor
intensive and require numerous resources for ENO to develop the allocation factors for the FRP
that would be required under the Advisors’ proposal;527 and
WHEREAS, Air Products argues that the structure of ENO’s and other parties’ decoupling
mechanisms poses a substantial risk of a highly disruptive change in revenues for customers in
classes that have only a few customers (Master-Metered Nonresidential, Large Electric High
Voltage and Large Interruptible Service) because the mechanism essentially would guarantee fixed
cost recovery from those classes regardless of the level of purchases by customers in those
classes.528 According to Air Products, a modest change in the level of business operations, and
hence the amount of power required from ENO, could cause a very disruptive increase to those
customers;529 and
WHEREAS, Air Products’ witness Mr. Brubaker recommended that one of two solutions
be applied to address the consequences that a decoupling adjustment could have on rate classes
with only a few customers. 530 Either customer classes with only a few customers should be
excluded from any decoupling mechanism, or there should be a maximum change of 10% in the
average charge per kWh between rate cases to customers in those classes;531 and
WHEREAS, the first recommendation of Mr. Brubaker is to exclude from the decoupling
mechanism those classes with only a few customers.532 As Mr. Brubaker points out, the revenues

526

Id. at 15:12-19.
Id. at 16:9-21.
528
Air Products’ Initial Brief at 10.
529
Id.
530
Id. at 41.
531
Id. at 11.
532
Id.
527

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 of these rate classes with only a few customers amount to less than 3% of total base rate revenues,
so this exclusion would not materially impact the operation of a decoupling mechanism;533 and
WHEREAS, in the alternative, Air Products asserts that should the Council not want to
exempt any customer rate classes from the decoupling mechanism, it should adopt Mr. Brubaker’s
recommendation to cap the percentage change in average revenue per kWh between rate cases that
result from the application of the decoupling mechanism to 10% for individual customers in rate
classes Master Metered Non-Residential, Large Electric High Voltage and Large Interruptible
Service, which would greatly reduce the potential for highly disruptive changes in these classes
rates;534 and
WHEREAS, Air Products requests that customer classes with few customers, including
rate classes Master Metered Non-Residential, Large Electric High Voltage and Large Interruptible
Service, either be exempt from the decoupling adjustment or have their exposure to changes in
rates between rate cases resulting from the decoupling adjustment capped at 10%;535 and
WHEREAS, the Advisors argue that the decoupling mechanism should operate within the
E-FRP, and should apply to proforma revenue requirements and billing determinants in the FRP
rate effective period to reduce regulatory lag and remove the need for LCFC;536 and
WHEREAS, the Advisors also argue that the concern of unintended consequences related
to a customer class with few customers is largely without merit because updating allocation factors
and billing determinants with current customer data in each E-FRP will accommodate any shifts
in customers or usage within these classes, and the customer class rates of return determined by
the customer class revenues set by the Council in the instant Docket would be the basis for the

533

Id.
Id. at 42.
535
Id. at 43.
536
Ex. No. ADV-5 at 29:3-30:4.
534

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 customer class return component in the FRP.537 Consequently, ENO’s argument regarding no
objective standard that can be replicated for the different ROR on rate base for each customer/rate
class is without merit; and
WHEREAS, the Advisors maintain that updated allocation factors are necessary to reflect
the change in usage patterns related to increased energy efficiency, distributed energy resources,
renewables including solar, new products and equipment, and other current impacts affecting
usage that were not as much of a concern in years previous;538 and
WHEREAS, the Advisors also argue that implementing the Advisors’ decoupling
recommendations will not require a level of effort comparable to a cost allocation study in a general
rate case, since using the same methodologies and models, with no requirement for two test periods
or weather normalization, minimal updating of weighting factors, and no change to the use of the
external and internal allocation factors in the cost of service model will not undermine the
efficiencies of the E-FRP;539 and
WHEREAS, despite its assertion that its proposal is the only one that complies with
Resolution No. R-16-103,540 ENO proposes that it not be required to meet the requirement of
Resolution No. R-16-103 that it recalculate a fixed-cost customer rate class allocation factor or
factors each year consistent with the cost allocation methodology used in this proceeding and use
those factors to allocate the FRP evaluation period electric revenue requirement to each rate
class.541 ENO argues that (1) strictly following the rate class cost allocation from the cost of
service study allocation factors would cause a disruptive increase in cost responsibility for the

537

Id. at 27:17:2.
Id. at 27:6-10.
539
Id. at 25:25:16-19 and 26:18-27:1.
540
ENO Reply Brief at 94.
541
ENO Initial Brief at 100.
538

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 Residential Rate Class, and (2) the Council had not adopted such a rate class cost allocation in its
last two rate cases.542 Instead, ENO proposes that the FRP Evaluation Period electric revenue
requirement be allocated consistent with the relative allocation of the base electric revenue among
the rate classes approved by the Council, absent some material change that indicated that relative
allocation should be modified;543 and
WHEREAS, the Advisors argue that ENO’s claim regarding a “disruptive increase in cost
responsibility for the Residential Rate Class” is not supported by any analysis. If the cost
allocation methodologies accepted by the Council in this docket are simply updated with current
billing determinants, a disruptive increase in cost responsibility is implausible, as is defining “some
material change” in ENO’s decoupling proposal; and
WHEREAS, the Council finds that it thoroughly examined the issue of decoupling in a
transparent docket open to all interested parties, and in which the AAE actively participated in
Docket No. UD-08-02. The outcome of that examination was the adoption by the Council of a
decoupling mechanism in Resolution No. R-16-03. Thus, the Council finds that the appropriate
consideration in this rate case is whether or not ENO’s decoupling proposal complies with the
Council’s instructions in Resolution No. R-16-03; it is not an appropriate proceeding for parties to
take “another bite at the apple” as to what the appropriate structure of the decoupling mechanism
is. That was decided in Resolution No. R-16-03, and the Council finds that no party has raised a
sufficient reason for the Council to re-open the decisions made in Resolution No. R-16-03 in this
proceeding; and
WHEREAS, while AAE urges the Council to reject the concept that stakeholders who
failed to participate in a previous process should “be forever barred from weighing in on an

542
543

Id.
Id. at 100-101.

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 issue,”544 that is not what is at issue in this proceeding. The Council must strike a balance between
striving to continually make improvements to its regulations and providing sufficient stability in
its regulations that regulated entities can understand what they must do to comply with the
Council’s regulations. It is not beneficial to any party for the Council’s regulations to be a constant
“moving target.” Under the facts presented in this case, the Council finds that the AAE and other
interested parties had sufficient opportunity to advocate for their desired decoupling structure in
Docket No. UD-08-02 and have not offered sufficient cause for the Council to take the unusual
step of altering its regulations through a rate case; and
WHEREAS, the Council finds that a full decoupling mechanism should be filed with each
electric E-FRP evaluation, with total allocated costs of service for each customer class included in
the decoupling revenue adjustment, and the customer rate class allocation factors be updated
annually with current billing determinants; and
WHEREAS, the Council finds that the decoupling adjustment be applied to all customer
classes if the E-FRP revenue adjustment is outside the bandwidth; and
WHEREAS, the Council has carefully considered Air Products’ arguments and alternative
proposals with respect to the potential impact of ENO’s proposed decoupling mechanism on rate
classes with only a few customers and believe that Air Products’ concerns are valid; and
WHEREAS, the Council finds that some protection should be provided for those rate
classes (Master Metered Non-Residential, Large Electric High Voltage and Large Interruptible
Service) having only a few customers to mitigate the potential exposure of those rate classes to
highly disruptive changes in rates that may occur as a result of the decoupling mechanism approved
in this case; and

544

AAE Reply Brief at 17.

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 WHEREAS, for rate classes Master Metered Non-Residential, Large Electric High
Voltage and Large Interruptible Service, a decoupling revenue adjustment cap of 10% shall apply
to each of the three annual FRP evaluation period revenue adjustments provided that the total
electric utility FRP revenue adjustment for that evaluation period does not exceed 10%; and
WHEREAS, the Council finds that a new baseline of customer class fixed and variable
revenue requirements be determined in each E-FRP from an allocation of costs and a return
component based on the rates of return corresponding to the customer class total revenues set in
the instant docket. Any adjustments that may be needed to the relative rates of return will be such
that those adjustments move the relative customer class rates of return toward the utility’s rate of
return based on the weighted average cost of capital; and
WHEREAS, the Council finds that the revenue deficiencies/excesses be determined for
each customer class by comparing the E-FRP customer class total revenue requirements with the
customer class evaluation period total actual revenues, with the decoupling adjustments applied
within each customer class using updated billing determinants excluding the customer charge; and
WHEREAS, the Council finds that the decoupling adjustment should apply to proforma
revenue requirements and billing determinants in the E-FRP rate effective period, based on
updated allocation factors and billing determinants in each E-FRP; and
WHEREAS, to the extent any undisputed element of ENO’s decoupling proposal is not
addressed herein, the Council has reviewed it and found it reasonable, and it is approved as
proposed by ENO; and

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 GREEN POWER OPTION
WHEREAS, ENO proposed a “green pricing proposal” in this case pursuant to Resolution
No. R-18-97. 545 Under ENO’s proposed Green Power Option (“Rider GPO”), a voluntarily
enrolled customer would be able to match some or all (i.e., 100%) of their electricity usage with
renewable energy certificates (“RECs”) sourced from renewable energy sources like wind and
solar;546 and
WHEREAS, a REC represents the environmental benefits of 1 MWh of renewable
energy.547 ENO argues that by purchasing and pairing RECs with their electricity service, retail
customers can use and receive the benefits of that renewable electricity.548 ENO argues that RECs
are used across the country as a low-risk option to support renewable energy and meet renewable
energy usage goals;549 and
WHEREAS, ENO’s proposed Rider GPO would be open to all customers and allow them
the option of matching 100%, 50%, or 25% of their electricity usage each month with RECs.550
ENO explains that nationally, demand for green pricing options provided by utilities has increased
substantially in recent years, and that, according to surveys conducted by ENO, approximately
36% of ENO’s customers have expressed interest in participating in a green power option;551 and
WHEREAS, under the proposal, ESI’s System Planning and Operations Organization
(“SPO”) would acquire and retire the RECs associated with the Green Power Option. 552 ENO
proposed that the offering be certified by “Green-e”, which, ENO explains, is an independent

545

Ex. No. ENO-55 at 41; Ex. No. ENO-19 at 41:4-16.
Ex. No. ENO-55 at 41; Ex. No. ENO-19 at 40:9-11.
547
Ex. No. ENO-55 at 41; Ex. No. ENO-19 at 40:13-15.
548
Ex. No. ENO-55 at 41.
549
Ex. No. ENO-55 at 41; Ex. No. ENO-19 at 40:18-41:2.
550
Ex. No. ENO-55 at 41; Ex. No. ENO-19 at 43:15-17.
551
Ex. No. ENO-19 at 41:17-42:12.
552
Id. at 47:3-9.
546

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 consumer protection organization that offers certification and verifies the integrity of RECs
through the entire chain of custody, so customers can be confident in their purchase;553 and
WHEREAS, ENO’s proposed green power option would be available to all customer
classes and there will be no limit on the number of customers that can participate.554 Under ENO’s
proposal, there would be no minimum contract term for participation, though customers who
withdraw would not be eligible to return until after the seventh month following their
withdrawal.555 Customers would be allowed to change their election no more than one time in
any six-month period;556 and
WHEREAS, ENO’s proposed price for the Green Power Option would incorporate REC
prices (as driven by the national market), a small contingency to account for fluctuations in REC
prices and vendor support costs related to customer enrollment, customer education/marketing,
and Green-e certification.557 ENO proposed the following charges for each of the three options:558
Option

GPO Election

Rate (per kWh)

Tier One Option

25%

$0.015 per kWh

Tier Two Option

50%

$0.0125 per kWh

Tier Three Option

100%

$0.01 per kWh

WHEREAS, the options would be priced at different amounts in order to encourage
customers to choose to offset more of their usage with renewable energy.559 ENO’s proposed
pricing is based on assumptions regarding participation levels over the first three years, and to the
553

Id. at 44:1-4.
Id. at 44:18-21 and 45:18.
555
Id. at 46:6-10.
556
Id. at 46:13-14.
557
Id. at 47:12-21.
558
Id. at 48:6-10.
559
Id. at 48:12-14.
554

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 extent that actual participation levels and costs are significantly different than ENO’s assumptions
and/or change over time, ENO would seek pricing adjustments, though ENO does not anticipate
that adjustments would be needed frequently;560 and
WHEREAS, the Advisors estimate that under ENO’s proposed rate, a 1,000 kWh per
month customer (which is approximately the average residential customer) who chose the 100%
Green Power Option would experience a surcharge on their bill of approximately $10/month. 561
The Advisors calculate that ENO would profit from Rider GPO, but not materially or over the
long term, and conclude that the estimated O&M costs related to the GPO Rider do not constitute
a substantial risk to ratepayers should ENO’s actual costs be less.562 The Advisors state that any
collections in excess of actual expenses would be corrected for prospectively as part of any FRP
evaluation;563 and
WHEREAS, BSI opposes the Green Pricing Proposal because BSI believes it will neither
lower rates, nor contribute to improving New Orleans’ local economics nor its local
environmental footprint, and proposes that all Green Pricing funds be invested in CLEP instead;564
and
WHEREAS, ENO argues BSI’s claims that CLEP is superior to the Green Power Option
are unsupported by any testimony and should be rejected;565 and
WHEREAS, the Council observes that there are no funds set aside for the Green Power
Option, rather, customers would on an individual basis, decide whether to participate, thus there

560

Id. at 49:6-11.
Ex. No. ADV-6 at 71:13-14.
562
Id. at 71:16.
563
Id. at 71:18-72:1.
564
BSI Post-Hearing Brief at 25.
565
ENO Reply Brief at 118.
561

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 are no “funds considered for Green Pricing” that can be directed to another purpose in the absence
of a Green Power Option; and
WHEREAS, the Advisors recommend that the Council approve Rider GPO because it
presents a valuable option for ratepayers who wish to offset the environmental impact of their
electricity consumption while imposing substantially no costs or risks to non-participants.566 The
Advisors also recommend that the Council evaluate the programs’ actual costs of operation as
part of future rate actions, such as FRP evaluations, and take any further appropriate action at that
time, including adjustments to Rider GPO’s rates;567 and
WHEREAS, AAE and the Sierra Club argue that ENO’s proposed Rider GPO should be
modified in two ways: (1) rather than using Green-e certified RECs to verify that green power is
used, the Council should direct ENO to define explicitly green energy as actual clean resources,
i.e., solar, wind, and battery storage; and (2) the Council should direct ENO to include language
in the Rider GPO tariff that expressly states that any costs or expenses not recovered from
participants may not be recovered from ratepayers;568 and
WHEREAS, with respect to the first point, AAE and Sierra Club argue that Green-e is
not regulated by the Council and the Council has no control over what resources are designated
as green resources.569 They argue that this is a problem because some states may include energy
generated from black liquor or waste to energy facilities in their renewables portfolio standards
that ultimately determine whether a resources is “green” within that state or not. AAE and Sierra

566

Ex. No. ADV-6 at 72:6-9.
Id. at 72:12-15.
568
AAE/Sierra Club Initial Brief at 52-53.
569
Id. at 52.
567

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 Club view these types of resources “unclean” and only want solar, wind, and battery storage
resources to be included;570 and
WHEREAS, ENO argues in response to the AAE and Sierra Club that Resolution No. R18-97 simply required ENO to make a “proposal under which customers may voluntarily choose
to have some or all of the electricity supplied by renewable resources” and did not otherwise
define “renewable resources.”571 ENO argues that AAE submitted no testimony or evidence in
support of its argument that the scope of allowed resources should be narrowed; and
WHEREAS, the Advisors note that the Council currently has an RPS rulemaking docket
open, Council Docket No. UD-19-01, where the issue of what energy resources the Council would
deem as eligible to be considered “renewable resources” is being actively considered. 572
Therefore, the Advisors believe it is premature for the Council to rule in this rate case what should
and should not be considered an “eligible” resource for the Green Power Tariff.573 The Advisors
also argue that it would be unnecessarily burdensome for ENO to comply with and the Council to
enforce two separate definitions of “renewable energy,” one for the Rider GPO and different one
for the RPS.574 The Advisors agree, however, that only RECs that would otherwise satisfy the
Council’s definition of renewable resources are appropriate for inclusion in the program; 575 and
WHEREAS, ENO argues that Green-e is an independent consumer protection
organization that verifies that the RECs procured by the Company are (a) sourced from facilities
that meet quality criteria that has been endorsed by diverse stakeholder group; (b) marketed
transparently and honestly; and (c) delivered exclusively to the purchaser of the REC, i.e., that

570

Id.
ENO Reply Brief at 116, citing Resolution No. R-18-97, at P 9 (emphasis added).
572
Advisors’ Reply Brief at 53.
573
Id. at 53-54.
574
Id. at 54.
575
Id.
571

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 the renewable attribute of the generation is not used toward a state renewable energy mandate or
otherwise double-counted.576 ENO notes that Green-e has specific minimum criteria related to:
facility online date, REC vintage, and eligible resource types, yet it also allows flexibility in
design;577 and
WHEREAS, the Advisors also argue that any program based upon RECs must utilize
some method of certifying the RECs as green resources to ensure that the source of the REC is
known and that the REC is not double-counted (i.e. both sold to ENO and used to satisfy the RPS
requirement in the state in which it was generated, or sold to more than one customer).578 Greene is a nationally known and widely used service that performs such tracking and certification.579
Therefore, the Advisors believe that use of Green-e certification, or a similar certification, for any
RECs purchased by ENO for the Rider GPO would be appropriate.580 Therefore, the Advisors
recommend that the Council put in a requirement that RECs used for the Rider GPO must both
(1) be certified by Green-e; and (2) conform to the definition of renewable resources ultimately
adopted by the Council in Docket No. UD-19-01.581 To the extent that there is not a final Council
decision in Docket No. UD-19-01 prior to the implementation of the Rider GPO, the Advisors
recommend that ENO be allowed to utilize any Green-e certified RECs until such time as the
Council renders a decision in Docket No UD-19-01, at which point, ENO must conform its use
of RECs to the Council’s definition of renewable resources on a going-forward basis;582 and

576

ENO Reply Brief at 116.
Id.
578
Advisors’ Reply Brief at 54.
579
Id.
580
Id.
581
Id.
582
Id.
577

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 WHEREAS, the Advisors are concerned about the proposal to include storage as a
renewable resource because storage is not inherently a renewable form of electricity. 583 The
Advisors note that (1) storage does not actually generate any electricity, it merely stores electricity
generated by a generator until a more advantageous time to utilize that electricity and (2) the
electricity from any given storage battery may or may not have originally been generated by a
renewable resource.584 The Advisors note, for example, that although many home batteries are
coupled with a rooftop solar unit, there is no requirement that they be, and homeowners can easily
install a home battery that is simply charged with electricity from the local utility, which is a mix
of any number of renewable and non-renewable resources. 585 Therefore, while the Advisors
would not exclude from eligibility any RECs originally from an energy source that have passed
through a storage battery, the Advisors recommend that any such REC be able to demonstrate that
the original source from which the electricity was generated was in fact a renewable resource and
that the REC be Green-e certified so that the renewable properties of the electricity cannot be
double-counted;586 and
WHEREAS, with respect to AAE and Sierra Club’s second proposed modification, that
ENO be required to include express language in the Green Power Option tariff that expressly
states that any costs or expenses not recovered from participants may not be recovered from
ratepayers, ENO argues that Resolution No. R-18-97 requires that “[t]he green pricing proposal
should reflect to a reasonable extent ENO’s incremental net cost to provide this option to
customers.”587 ENO argues that its testimony demonstrates that the pricing has been designed

583

Id.
Id. at 54-55.
585
Id. at 55.
586
Id.
587
ENO Reply Brief at 117, citing Resolution No. R-18-97.
584

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 such that it is “reasonably assured” that the price of the RECs and incremental costs of offering
the product will be recovered from participants.588 ENO also states that actual participation levels
and costs will be monitored, and ENO will seek adjustments, subject to Council approval, if
warranted;589 and
WHEREAS, the Advisors advise the Council that AAE and Sierra Club’s
recommendation that ENO be required to include express language in the Green Power Option
tariff that expressly states that any costs or expenses not recovered from participants may not be
recovered from ratepayers is inconsistent with the regulatory doctrine that the utility must be
allowed sufficient revenues to meet its operating expenses, provide its shareholders with a
reasonable ROR and attract new capital. 590 The Advisors explain that such costs must be
recovered from the utility’s customers, either the customers participating in the program or the
non-participating customers.591 It is the Advisors’ expectation that there will be enough interest
in the program that there will be a sufficient number of participating customers to cover the
program’s costs, and that in the event that there are not, the costs would be de minimis as testified
to by ENO witness Owens.592 The Advisors argue that because there is value to customers in
being given an option, such as the Rider GPO, even if those customers do not take advantage of
it, it would be reasonable for non-participating customers to bear such de minimis costs in the
event the program does not prove to be popular;593 and
WHEREAS, the Advisors, however, would not endorse a blank check to ENO to pass
through any and all costs, whether reasonable or not, or to run an unsuccessful program

588

Id., citing Ex. No. ENO-19 at 48.
ENO Reply Brief at 117, citing Ex. No. ENO-19 at 49.
590
Advisors’ Reply Brief at 55, citing Cent. Louisiana Elec. Co. v. Louisiana Pub. Serv. Comm’n, 508 So. 2d at
1364-65, citing So. Cent. Bell Tel. Co. v. Louisiana Pub. Serv. Comm’n, 352 So. 2d at 967.
591
Advisors’ Reply Brief at 55.
592
Id., citing City Council Hearing Transcript, 118:22-23 (June 19, 2019).
593
Advisors’ Reply Brief at 55-56.
589

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 indefinitely, because it would provide ENO with no incentive to design the program well or
negotiate for reasonably priced RECs, etc. 594 Therefore, the Advisors recommend that the
Council require that, in the instance where there are not enough customers participating in the
Green Power Option to bear the costs of the program fully, ENO should be allowed to recover
costs from non-participating ratepayers, but only after submitting such costs to the Council for
review and demonstrating to the Council’s satisfaction that the costs were prudently incurred,
along with a request to either terminate or alter the program.595 The Advisors argue that this
solution would uphold the requirements of Hope and Bluefield, while preserving the Council’s
ability to protect ratepayers from having to bear imprudently incurred expenses and providing
ENO with an incentive to run the program well;596 and
WHEREAS, having considered the arguments of the parties, and considering that Council
Docket No. UD-19-01 is ongoing and is actively considering both what resources should be
defined as “renewable resources” under the Council’s rules and regulations and what certifications
would be required for RECs from such resources, the Council finds that ENO’s Green Pricing
Proposal should be approved with the following modifications:


to the extent that the Council establishes a definition of “renewable resources” in
Docket No. UD-19-01, RECs used for the Green Power Option must originate
from sources meeting that definition;



to the extent the Council adopts a requirement in Docket No. UD-19-01 that RECs
be certified and/or tracked through a particular program(s), such as Green-e, then
RECs used for the Green Power Option must be certified and/or tracked in the
same manner, however, if the Council does not establish such a requirement in
Docket No. UD-19-01, then RECs shall be certified through Green-e (or such other
certification as the Council may approve in the future); and



ENO’s pricing proposal is approved but shall be modified to clarify that in the
instance where there are not enough customers participating in the Green Power

594

Id. at 56.
Id.
596
Id.
595

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 Option that the participating customers could reasonably be expected to bear the
full costs of the program under the approved pricing structure, ENO should be
allowed to recover remaining costs from non-participating ratepayers after
submitting such costs to the Council for review and demonstrating to the Council’s
satisfaction that the costs were prudently incurred, along with a request for Council
authorization to either alter the program to ensure that there is reasonable assurance
that costs of the program will be paid by participating customers going forward, or
a request to terminate the program; and
WHEREAS, the Council agrees with the Advisors’ suggestion that to the extent that there
is not a final Council decision in Docket No. UD-19-01 prior to the implementation of the Green
Power Option, ENO be allowed to utilize any Green-e certified RECs until such time as the
Council renders a decision in Docket No. UD-19-01, at which point, ENO must conform its use
of RECs to the Council’s definition of renewable resources and certification and/or tracking
requirements on a going-forward basis; and
COMMUNITY SOLAR
WHEREAS, ENO and BSI both propose some form of community solar program or
pricing in this case. ENO proposes its Community Solar Offering (“Schedule CSO”) while BSI
proposes its CLEP community solar rate; and
(1)

ENO Proposal

WHEREAS, ENO proposes a new community solar offering whereby participants
voluntarily pay for a specific allocation of offsite solar PV projects, and in return for an upfront
or ongoing payment, the participant receives a credit on his or her monthly electric bill, tied to the
actual output of the solar PV project.597 ENO proposes to use both its existing ~1 MWAC solar
project located at the Paterson site along with the recently approved 5 MWAC rooftop solar
project.598 ENO argues that using existing projects allows interested customers to sign up for a

597
598

Ex. No. ENO-55 at 39.
Ex. No. ENO-10 at 41:16-18.

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 program based on real-life systems as opposed to having to wait until enough interest has been
expressed before ENO can move forward with constructing a resource to support community
solar;599 and
WHEREAS, ENO’s proposed program would be open to both residential and nonresidential customers on non-lighting rate schedules, subject to a few limitations.600 ENO has
designed its proposal as a “pay-as-you-go” model to maximize participation.601 The monthly
charge ENO proposes would be fixed for the duration of the offering and is set at $15.00 per
kWAC based on the customer’s allocated share in kW.602 ENO designed this rate to cover the
incremental costs associated with using an outside vendor to get ENO’s community solar offering
up and running, as well as the monthly bill credits that customers receive for participating; it is
not meant to cover the upfront and ongoing costs of the solar assets that underpin the offering those costs will be reflected in overall rates that all customers pay. 603 ENO proposes that the
credit rate that is applied to the customer’s allocated share of the actual output of the solar systems
that underpin the community solar offering be based on two components: the historic embedded
value of generation, which is adjusted from time to time, and the current FAC value. 604 ENO
states that any verified RECs produced by the solar systems that underpin the offering would
belong to ENO, would be retired each year, and would not be transferred in any manner to
subscribing customers;605 and

599

Id. at 41:20-42:3.
Id. at 42:15-17.
601
Ex. No. ENO-55 at 39; Ex. No. ENO-10 at 43:19-20.
602
Ex. No. ENO-55 at 39; Ex. No. ENO-10 at 44:1-3.
603
Ex. No. ENO-10 at 44:10-22.
604
Ex. No. ENO-55 at 39; Ex. No. ENO-10 at 45:3-8.
605
Ex. No. ENO-10 at 49:11-13.
600

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 WHEREAS, the Advisors argue that one of the principles established by the Council with
regards to community solar programs was the principle of a level playing field. 606 In Resolution
No. R-18-223, the Council specifically indicated that:
In order to ensure a level playing field, to the extent that ENO chooses to become
a community solar developer, it must offer the same privileges it allows itself to all
other developers. ENO may not give itself preferential treatment as a developer of
a community solar project and may not use ratepayer funding for its community
solar projects in any manner not available to other developers;607 and
WHEREAS, the Advisors argue that ENO’s proposed Community Solar Offering may
result in preferential treatment for ENO that may discourage other Community Solar developers
from developing projects in New Orleans under the Council’s Community Solar Rules, because,
it is ensured to recover its prudently incurred costs of any solar projects, regardless of the number
of subscribers its Community Solar Offering has, or whether the fees and credits for its
participants fully offset the costs of the projects;608 and
WHEREAS, this guarantee that ENO would fully recover their costs even if it is not able
to attract a sufficient number of subscribers or charge a high enough price, the Advisors argue, is
an advantage that other community solar developers will not have.609 The Advisors express doubt
that that approving ENO’s Community Solar Offering could bring community solar to New
Orleans faster than allowing the market to form naturally under the Council’s Community Solar
Rules, and argue that it may permanently impair the market by preventing competing developers
from being able to compete with ENO;610 and
WHEREAS, the Advisors also argue that ENO’s proposed Community Solar Offering
monthly charge is designed to recover only the incremental administrative and marketing costs
Advisors’ Initial Brief at 129.
Resolution No. R-18-233 at 3.
608
Advisors’ Initial Brief at 129, citing Ex. No. ADV-1 at 44:12-15 and 44:16-20.
609
Id.
610
Id.
606
607

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 and the cost of providing solar credits to all potential participants at the retail rate, while the
Community Solar Rules clearly state that the capital and operating costs of a community solar
garden facility will not be recovered from ratepayers, but rather those costs are the responsibility
of the developer/owner of the community solar garden to be recovered from the participants in
it.611 The Advisors argue that ENO’s proposal violates this, by requiring ENO ratepayers to pay
for a portion of the facilities’ fixed costs;612 and
WHEREAS, in addition, the Advisors argue that ENO’s proposed credit for community
solar is valued differently than the credit in the Council’s Community Solar Rules, and that it
would be preferable to have only one methodology for determining the appropriate credit for
community solar offerings;613 and
WHEREAS, ENO acknowledges that its proposed Community Solar Offering Rider does
not comply with the Council’s Community Solar Rules, but argues that it has sought approval
despite those variances and demonstrated with undisputed evidence why Rider CSO can bring
greater benefits to customers than if it were modified to conform to the Council’s Rules;614 and
WHEREAS, ENO also argues that it has attempted to justify its Community Solar
Offering in this proceeding and that ENO is entitled to an adjudication on the merits of its proposal
in this proceeding based on any regulatory requirements that existed at the time the proposal was
filed.615 ENO argues that customers who enroll in its program would be able to switch to other
developers later without any penalties if the Council’s community solar initiative ultimately
attracts any, and would allow ENO to gain experience with the administration of a community

611

Id., citing Ex. No. ADV-3 at 72:4-6 and 72:17-73:1.
Id., citing Ex. No. ADV-3 at 73:1-9.
613
Id., citing Ex. No. ADV-1 at 45:2-9 and 45:9-10.
614
ENO Post-Hearing Brief at 168.
615
Ex. No. ENO-12 at 39:6-9; Ex. No. ENO-13 at 12:12-13:18.
612

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 solar offering before the Council’s initiative gets under way. 616 ENO also argues that it may
reduce the incremental costs of administering the Council’s program, thus benefitting those
customers as well.617 ENO argues that its proposal will bring greater benefits than the Council’s
Community Solar Rules because (1) it will not require the Council or CURO to create additional
regulatory mechanisms for the oversight of ENO’s proposed rider; (2) it provides the opportunity
for customers to participate in “Utility-Scale” offerings that could help to offset the revenue
requirements associated with ENO’s commitment to add up to 100 MW of renewable energy to
its generation portfolio; (3) it would mean that customers have a community solar option in a
more timely manner.618 ENO argues that it would be counterproductive and wasteful for the
Council to reject ENO’s proposal;619 and
WHEREAS, ENO argues that the evidence about the potential benefits of ENO’s
proposed CSO is undisputed and that the Advisors’ criticisms and recommendations lack any
foundation in evidence submitted in this proceeding. 620 ENO argues that its proposal can be
viewed as complementary to, but deliberately designed to be separate from, the Council’s
program.621 ENO also argues that its proposal has the potential to be available much sooner than
any offerings developed through the Council’s framework;622 and
WHEREAS, the Advisors argue that ENO misrepresents the Advisors’ primary
concern.623 The Advisors argue that the Council must still review ENO’s proposal and make sure
it is just and reasonable and while compliance with the Council’s Community Solar Rules would

616

Ex. No. ENO-12 at 39:16-22.
Id. at 39:22-40:3.
618
Id. at 41:9-42:8.
619
Id. at 44:12-13.
620
ENO Post-Hearing Brief at 166-167.
621
Id. at 167.
622
Id.
623
Advisors’ Reply Brief at 56.
617

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 create a presumption that it is just and reasonable, the fact that formal community solar rules were
not in place prior to ENO’s proposal does not mean that the Council is obligated to accept
whatever community solar project ENO proposes;624 and
WHEREAS, the Advisors do not believe that the potential near-term benefits of having
some form of community solar available to ratepayers more quickly and allowing ENO to gain
some experience administering a community solar program will be significant enough to offset
the potential damage to the long-term market;625 and
WHEREAS, AAE and the Sierra Club argue that the Council should reject ENO’s
specific community solar tariff because the Company failed to establish that the proposal would
bring greater benefits.626 They argue that both of the benefits ENO claims its proposed structure
would bring — being able to be in service more quickly and being able to offer it on a “pay-asyou-go” basis without long-term commitments — stem from ENO’s status as a regulated utility,
and its ability to provide the offering from solar projects that are fully supported by all ratepayers
in ENO’s rates.627 They argue that this advantage places other solar developers at a clear and
substantial disadvantage and, as a result, such developers may choose not to participate in the
New Orleans market.628 Thus, AAE and Sierra Club argue, ENO’s community solar offering does
not meet the standard established by the Council in Resolution No. R-19-11 of demonstrating that
the offering provides greater benefits than would a proposal conforming to the Council’s recently
adopted Community Solar Rules.629 To the contrary, they argue, ENO’s proposal creates the risk

624

Id. at 56-57.
Ex. No. ADV-5 at 37:11-19.
626
AAE/Sierra Club Initial Brief at 49.
627
Id. at 49-51.
628
Id. at 51.
629
Id.
625

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 of real harm to the nascent community solar market without presenting any real benefits to New
Orleans ratepayers, and should therefore be rejected;630 and
WHEREAS, ENO claims that the Advisors’ recommendation expresses a general
concern 631 that is unsubstantiated by any analyses, however, the Advisors argue that with
significant concerns having been raised by the Advisors, AAE and Sierra Club, ENO bears the
burden of demonstrating that its proposal is just and reasonable.632 Had the proposal been in
conformance with the Community Solar Rules, the Advisors argue, a presumption of
reasonableness would have been in place, but it is not in conformance, and the Advisors do not
believe that ENO has demonstrated that the benefits it claims from bringing community solar to
New Orleans faster and allowing a “pay-as-you-go” model (which others may or may not also be
able to offer) would outweigh the damage caused to the development of a competitive market for
community solar in New Orleans;633 and
WHEREAS, the Advisors argue that ENO has not made its case in this proceeding that
its proposed community solar program is just and reasonable or in the public interest. 634
Nevertheless, the Advisors recommend that the Council reject ENO’s proposal in this proceeding
without prejudice to ENO and being permitted to re-file either the same proposal or a modified
proposal in the Community Solar docket with more support as to the issue of whether ENO’s
proposed structure would bring greater benefits than would a proposal that conforms to the
Council’s Community Solar Rules.635 While ENO argues that requiring an additional filing would
create “administrative waste,” 636 the Advisors disagree, writing that the Council needs more

630

Id.
ENO Initial Brief at 167.
632
Advisors’ Reply Brief at 59.
633
Id.
634
Id.
635
Id. at 59-60.
636
ENO Initial Brief at 167.
631

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 information to consider the potential benefits and adverse impacts of ENO’s proposal, apart from
the focus of the ratemaking decisions of the instant docket;637 and
WHEREAS, ENO argues that the Advisors’ and AAE’s concerns about the potential
market effect of ENO’s Community Solar Offering are exaggerated.638 ENO argues that AAE
had not previously filed any testimony or otherwise previously taken a position on Community
Solar.639 ENO states that the concerns on the impact on the market are exaggerated because its
Community Solar offering is limited to 6 MW of solar capacity and that any future community
solar offerings made by the Company would be in accordance with the Council’s new rules that
were implemented after ENO made this rate case filing;640 and
WHEREAS, the Council is pleased that ENO has been developing a community solar
offering for its customers and encourages ENO to continue developing interesting new offerings
for its customers; and
WHEREAS, the Council shares the Advisors’ concerns that an improperly structured
community solar offering could impede the development of a local community solar market; and
WHEREAS, the Council rejects ENO’s Community Solar Offering as proposed in this
case, without prejudice to ENO proposing a revised Community Solar Offering in the future; and
(2)

BSI Community Solar Proposal

WHEREAS, BSI proposes a CLEP solar rate where the customer would receive the sum
of the monthly kWh produced by the customer’s share of the community solar project multiplied

Advisors’ Reply Brief at 60.
ENO Reply Brief at 101.
639
Id.
640
Id. at 101-102.
637
638

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 by ENO’s cost of energy plus the customer’s CLEPm payment or charge plus the monthly sum
of the customer’s CLEP5 payments and charges;641 and
WHEREAS, the Advisors observe that this would be instead of the community solar
payments set by the Council’s Community Solar Rules.642 However, the Advisors argue, while
BSI admits that its proposal would not be consistent with the Council’s Community Solar Rules,
BSI fails to demonstrate to the Council why its Community Solar proposal would provide greater
benefits than a proposal that complies with the Council’s rules.643 In addition, the Advisors argue,
the CLEP community solar proposal is too complex to be easily understood or implemented by
customers;644 and
WHEREAS, in adopting its Community Solar Rules, the Council explicitly left open the
opportunity for parties to propose community solar projects that do not directly conform to the
Council’s rules and set forth a requirement that parties proposing such a program demonstrate
why the alternative proposal brings greater benefits than a proposal conforming to the Community
Solar Rules would bring.645 However, the Advisors argue that BSI has not demonstrated that its
community solar proposals provide greater benefit to ratepayers than a community solar project
structured under the Council would. 646 Therefore, the Advisors do not recommend that the
Council implement CLEP community solar;647 and
WHEREAS, while BSI argues that its CLEP proposal generally meets several Council
objectives, it provides little description of how the CLEP Community Solar proposal would
provide greater benefits to ratepayers than a program designed consistently with the Council’s

641

Ex. No. BSI-1 at 17:16.
Advisors’ Initial Brief at 130, citing Ex. No. BSI-1 at 18:3-6.
643
Id. at 130.
644
Id. at 130-131.
645
See Resolution No. R-18-538 at 30-31.
646
Advisors’ Initial Brief at 131.
647
Id.
642

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 Community Solar Rules, other than that CLEP payments would exceed payments to community
solar participants under the Council’s Community Solar rules;648 and
WHEREAS, BSI explains in Appendix 1 of its Reply Brief that it estimates that the CLEP
Community Solar price would pay 17% more to participating customers than the retail cost of
electricity.649 BSI also notes in its Initial Brief that CLEP is helpful to community solar by paying
10% higher than retail.650 However, BSI fails to explain why requiring ENO to pay community
solar participants far more per kWh for the electricity they produce than ENO pays for the power
it already provides ratepayers will bring more benefits to New Orleans ratepayers than the
Council’s Community Solar Rules, which endeavor to balance the interests of participating and
non-participating customers; and
WHEREAS, BSI argues that CLEP is superior to the Council’s Community Solar Rules
adopted in Resolution No. R-19-111 because those rules assume that the primary way community
solar will be implemented is through utility ownership, but treating Community Solar Farms as
private enterprises moots most of the issues addressed in Resolution No. R-19-111.651 However,
the characterization of Resolution No. R-19-111 demonstrates a complete misunderstanding of
that Resolution. Resolution No. R-19-111 and the Community Solar Rules adopted therein clearly
contemplates that a Community Solar facility could be owned either by the utility or by any other
for-profit or not-for-profit entity or organization;652 and

648

BSI Reply Brief at 19.
Id. at Appendix 1.
650
Id. at 5.
651
BSI Post-Hearing Brief at 24-25.
652
Resolution No. R-19-111, Appendix A at II, Definition of Community Solar Generating Facility.
649

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 WHEREAS, in light of BSI’s apparent misunderstanding of the Community Solar Rules,
the Council gives no weight to BSI’s arguments as to how CLEP benefits exceed those of the
Community Solar Rules; and
COST RECOVERY FOR THE ENERGY SMART PROGRAM EECR/DSMCR
WHEREAS, as the Advisors explain, the Council has long recognized energy efficiency
and demand response offerings (collectively “demand-side management” or “DSM”) as highpriority resources for serving ENO’s customers, and in 2009, established the Energy Smart
program to encourage the development of such resources in New Orleans by offering various
programs and incentives for customers wishing to implement DSM measures to reduce their
energy use;653 and
WHEREAS, the Energy Smart Program is now nearing the end of Program Year 9, and
has been funded through a variety of mechanisms over the first nine years of its existence. 654 The
program has been highly successful, having received the U.S. Environmental Protection Agency’s
Partner of the Year Award in both 2014 and 2016, a Pro 3 award from the Southeast Energy
Efficiency Alliance and a first-in-the-nation ranking in an American Council for an EnergyEfficient Economy study with respect to the kWh savings per participant for low-income
customers.655 The program, however, has lacked a stable and predictable funding source;656 and
WHEREAS, in this case ENO proposes a new model for cost recovery related to DSM
initiatives offered through Energy Smart.657 ENO’s model would use a rider for Energy Smart
funding, incorporating a regulatory asset that would earn a return and be amortized over three

See Resolution No. R-09-136. See also, Resolution Nos. R-07-600 and R-09-483; Advisors’ Initial Brief at 67.
Advisors’ Initial Brief at 67.
655
Ex. No. ENO-10 at 9:18-24, citing http://aceee.org/sites/default/files/low-income-baseline-0717.pdf.
656
Id. at 11:1-3.
657
Id. at 3:10-12.
653
654

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 years, to recover the costs of each Program Year (“PY”) of Energy Smart. 658 Under ENO’s
proposal the return and ROR that ENO would earn on the regulatory asset would function as an
incentive mechanism for achieving the savings goals established during the Integrated Resource
Plan (“IRP”) process.659 The rider would also recover the LCFC, but would not include those
dollars as part of the regulatory asset.660 ENO argues that its proposed model would fulfill the
Council’s directive that demand-side resources should be on an equal financial footing with
traditional supply-side resources;661 and
WHEREAS, ENO argues that cost recovery for DSM offerings must fairly address
(1) direct and indirect costs of DSM offerings;662 (2) LCFC and (3) some form of incentive, and
that these three elements will “level the playing field” between DSM and supply-side alternatives
and will increase the likelihood that a utility will maximize the utilization of cost-effective DSM
to meet customer needs;663 and
WHEREAS, ENO is proposing implementation of two separate riders as funding
mechanisms -- one to continue funding for Energy Smart through the end of PY 9, the Interim
Energy Efficiency Cost Recovery Rider (“Interim EECR”), and another mechanism intended to be
applied for PY10 and beyond, the Demand-Side Management Cost Recovery Rider (“Rider
DSMCR”);664 and

658

Id. at 3:12-17.
Id. at 3:17-21l; ENO Initial Post-Hearing Brief at 111.
660
Ex. No. ENO-10 at 3:20-4:1; ENO Initial Post-Hearing Brief at 111.
661
Ex. No. ENO-10 at 5:8-11.
662
Such costs would include direct incentives paid to customers and other direct costs, ENO labor costs and indirect
costs necessary to develop and administer the DSM offerings and provide reporting, and amount paid to ENO’s
vendors for development and administration of DSM offerings as well as separate EM&V services. Id. at 21:9-15.
663
Ex. No. ENO-10 at 18:11-18; see also Ex. No. ENO-55 at 33.
664
Ex. No. ENO-10 at 14:3-5; ENO Initial Brief at 112.
659

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 INTERIM ENERGY EFFICIENCY COST RECOVERY RIDER
WHEREAS, ENO designed the Interim EECR to contemporaneously recover the Councilapproved funding for Energy Smart from customers for the period of August 2019 until December
2019665 (the period between when the new rates go into effect and the end of PY9). ENO proposes
that it would serve as an interim universal funding mechanism for both the Legacy ENO and
Algiers Energy Smart offerings approved in Resolution No. R-17-623.666 ENO states that the
Council approved a similar Interim EECR in Resolution No. R-17-623 that was never implemented
due to the availability of funding from another source667 and that ENO’s proposed Interim EECR
Rider in this proceeding utilizes the allocation factors that the Council approved in Resolution No.
R-17-623.668 ENO does not propose to implement the Interim EECR Rider as a line item on
customers’ bills;669 and
WHEREAS, the Advisors support the use of the Interim EECR,670 and no party opposes
the Interim EECR; and
WHEREAS, the Council finds the use of the Interim EECR to be reasonable; and
DSM COST RECOVERY RIDER
WHEREAS, the second mechanism ENO proposes for recovery of its costs associated
with DSM, its Rider DSMCR, is for PY 10 and beyond. 671 ENO proposes Rider DSMCR in
response to the Council Resolutions aimed at identifying a permanent funding mechanism for
DSM customer offerings (Resolution Nos. R-17-504, R-17-623, and R-17 176).672 ENO argues

665

Ex. No. ENO-10 at 14:17-19.
Id. at 14:10-12.
667
Resolution Nos. R-17-623 and R-18-227.
668
Ex. No. ENO-10 at 15:1-2.
669
Id. at 15:5-7.
670
Ex. No. ADV-3 at 9:11-13, 68:3-13.
671
Ex. No. ENO-10 at 15:11-14.
672
Ex. No. ENO-55 at 33.
666

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 that running DSM costs through a rider allows the Council, its Advisors, and other stakeholders to
specifically identify and track the level of ENO’s investments in DSM and the recovery of those
investments and that the use of a rider provides greater stability and facilitates planning by
providing a long-term mechanism for helping to ensure that funding will be available, and a rider
was clearly identified in Resolution No. R-17-623 as the preferable long-term approach.673 ENO
also argues that use of a rider that is updated annually provides a clearer path for the Council to
incorporate changes to Energy Smart, or add other DSM offerings to ENO’s demand-side
portfolio, which would allow for greater flexibility in responding to customer needs. 674 ENO is
not proposing that the rider appear on the customer’s bill, rather that it be included within another
line item such as the Energy Charge. 675 ENO’s proposed Rider DSMCR would have four
components;676 and
WHEREAS, the first component would be the total balance associated with the DSM
investment.677 ENO’s Rider DSMCR would utilize regulatory asset-based cost recovery model to
allow DSM investment to be treated more equivalently to traditional supply-side and other
investments in capital assets. 678 ENO argues this treatment would also initially help mitigate
higher bill impacts that would otherwise occur with full contemporaneous cost recovery.679 ENO
proposes to amortize its total DSM investments over a three-year amortization period;680 and
WHEREAS, AAE opposes the Rider DSMCR rate design. AAE urges the Council to
reject ENO’s proposal to effectively “rate base” DSM expenses.681 AAE also argues that the

673

Ex. No. ENO-10 at 16:21-17:11, see also Ex. No. ENO-55 at 33.
Id. at 17:11-15.
675
Ex. No. ENO-10 at 17:19-21.
676
Id. at 19:16-18.
677
Id. at 19:11-12.
678
Id. at 19:4-6 and 23:13-15; Ex. No. ENO-14 at 24:17-23.
679
Ex. No. ENO-10 at 19:6-8; Ex. No. ENO-14 at 25:1-4.
680
Ex. No. ENO-10 at 22:6-18; ENO Initial Brief at 111.
681
AAE/Sierra Club Initial Brief at 32.
674

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 percentage of bill-based design effectively increases the fixed charge that a customer pays each
month, which dampens the energy conservation price signal.682 Additionally, AAE argues it is
inappropriate because the objective of avoiding future energy supply costs and potentially
distribution infrastructure costs does not have a customer-specific component or any other
relationship to costs associated with connecting a customer to the grid. 683 AAE argues that a
volumetric charge should be used for Rider DSMCR. 684 AAE recommends the following
modifications to the Rider DSMCR: (1) a meaningful minimum savings threshold below which
ENO recovers expenses but receives no return on those expenses and is subject to a penalty
equivalent to the value of foregone cost savings for failing to achieve the minimum threshold; (2) a
more granular formulaic incentive calculation system in place of the large “steps” in ENO’s
proposal; and (3) a cap on total incentive awards;685 and
WHEREAS, in response to AAE’s argument that the Council should reject any DSM cost
recovery that allows ENO to “rate base” DSM, ENO argues that this ignores the Council’s goals
of aligning the incentives equally for DSM and supply-side resources and providing a comparable
earnings opportunity;686 and
WHEREAS, ENO argues that in order to level the playing field between supply-side and
demand-side investments, incentive mechanisms should seek to approximate what the utility
would have earned by investing the same amount of capital in a traditional asset;687 and
WHEREAS, the Advisors believe it would be reasonable to use the proposed EECR Rider
as the permanent mechanism to recover the costs (which have all been expenses and not capital

682

Ex No. AAE-3 at 53:19-54:1.
Id. at 53:1-5.
684
Id. at 54:19-20.
685
Ex. No. AAE-5 at 14:18-15:5.
686
ENO Reply Brief at 78.
687
Id. at 80.
683

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 investment) of the Energy Smart program for both Legacy ENO customers and Algiers customers,
and that the Rider DSMCR should not be implemented.688 The Advisors also recommend that
prospective Energy Smart costs beyond 2019 be included in each FRP evaluation;689 and
WHEREAS, AAE and Sierra Club support the Advisors’ proposal to reject the proposed
DSMCR Rider and make Interim EECR Rider proposed by ENO the permanent cost recovery
method, and they propose removing language referencing LCFC from the EECR Rider and instead
addressing the LCFC with the Advisors’ proposal to allow for pro forma adjustments to evaluation
period filling determinants for the twelve months subsequent to the FRP evaluation period;690 and
WHEREAS, while ENO argues that Rider DSMCR would initially have a lower impact
on customers, the Advisors argue that customers will pay less in total costs by recovering Energy
Smart costs contemporaneously as expenses, rather than by deferring expenses and treating them
as a regulatory asset.691 Moreover, the Advisors argue, ENO is not proposing a true regulatory
asset treatment, because ENO makes no attempt to match the term of the deferral of the payment
of costs to the life of the DSM measures being funded, which is typically more in the 10-20 year
range than in the three-year range. 692 Thus, the Advisors conclude, Rider DSMCR does not
propose a true leveling of the playing field between DSM and traditional supply-side assets;693 and
WHEREAS, the Advisors also argue that regulatory asset treatment is appropriate if a
large, non-recurring cost is recovered over several future years, whereas Energy Smart costs recur
every year, and are only likely to increase as the program pursues the Council’s goal of increasing
savings until it reaches 2% of annual sales.694 The Advisors note that ENO witness Dr. Faruqui
Ex. No. ADV-3 at 68:7-13; Advisors’ Initial Brief at 71.
Ex. No. ADV-3 at 68:10-11; Advisors’ Initial Brief at 71.
690
AAE/Sierra Club Reply Brief at 11-12.
691
Ex. No. ADV-3 at 69:4-7; Advisors’ Initial Brief at 71-72.
692
Advisors’ Initial Brief at 72.
693
Id.
694
Ex. No. ADV-3 at 68:1-3 and 69:4-10; Advisors’ Initial Brief at 72.
688
689

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 argues that while it is true DSM costs would not typically be recovered as a regulatory asset, the
traditional regulatory paradigm can act as a road block to encouraging aggressive and effective
DSM, and ENO has proposed a progressive solution to encourage innovation.695 The Advisors,
however, are not persuaded that a “progressive solution” that requires ratepayers to pay more in
nominal dollars than they otherwise would for DSM in order to allow the utility to earn a return
on DSM investment (as deferred expenses) is a solution that benefits ratepayers in the long term;696
and
WHEREAS, the Advisors argue that while ENO performed and presented an analysis
comparing net present values of funding options to demonstrate that ratepayers will ultimately
save money with the proposed DSMCR Rider,697 ENO’s Net Present Value calculations hinge on
ENO’s assumptions regarding the time value of money -- essentially how much benefit a customer
receives by being able to make use of their money over the time period for which payment is
deferred.698 The Advisors explain that, as ENO’s witness Owens conceded at hearing, ENO’s
calculations of the value customers receive by being able to spread the costs over three years rather
than by paying the costs up front are essentially based on the assumption that on average,
customers could earn a return on their money of 7.78% over the time that the customer is able to
keep the money. 699 The Advisors argue that this is an overly optimistic expectation of what
customers, on average, would be able to achieve in the market or other investment vehicles if they
could invest the amounts they defer paying to ENO, and therefore, the Advisors dispute ENO’s

Ex. No. ENO-14 at 10:18-11:10; Advisors’ Initial Brief at 72.
Advisors’ Initial Brief at 72.
697
Ex. No. ENO-12 at 18:9-22:4.
698
Advisors’ Initial Brief at 72.
699
Id. at 72-73, citing City Council Hearing Transcript, 137:20-138:16 (June 19, 2019). See also, Ex. No. ENO-12 at
19:21-23 demonstrating the average cost of capital utilized was 7.78%.
695
696

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 claim that the analyses demonstrate that Rider DSMCR will actually have less of an effect on
customers than Rider EECR;700 and
WHEREAS, the Advisors argue that regulatory asset treatment is typically approved for
non-recurring costs, like the construction of a power plant, while recurring and increasing annual
costs, like those associated with the Energy Smart program, are typically treated as expenses and
paid as they are incurred.701 The Advisors point out that ENO concedes that ratepayers would pay
substantially more in nominal dollars under the Rider DSMCR than under the EECR Rider, and
ENO’s net present value analysis attempting to demonstrate that customers are better off in the
long term was based on an unreasonable assumption regarding the time value of money;702 and
WHEREAS, while the Advisors express appreciation for ENO’s stated intent to create a
level playing field between supply-side and demand-side resources, they argue if ENO truly
desired to create a level playing field, it would amortize the costs of each DSM program year over
the life of the DSM resource (typically 10-20 years) rather than only for a three-year period;703 and
WHEREAS, ENO argues that while the EECR arguably meets the goal of providing stable
and predictable funding, it falls well short of meeting the Council’s other goals. 704 ENO also
argues that the EECR lacks a mechanism for recovery of LCFC and a reasonable performance
incentive commensurate with the expected investments in Energy Smart. 705 ENO argues that the
DSMCR proposal is the best cost recovery method proposed in this case because it provides the
stable and predictable source of funding and it aligns incentives equally for DSM and supply-side
resources and provides the opportunity to earn a comparable return;706 and
Advisors’ Initial Brief at 73.
Id. at 81.
702
Id.
703
Id. at 80-81.
704
ENO Reply Brief at 75.
705
ENO Initial Brief at 115.
706
ENO Reply Brief at 75.
700
701

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 WHEREAS, ENO argues that the company proposed a three-year amortization period
rather than a life-of-measure amortization period because it ties directly to the Council’s practice
of approving portfolios and budgets for DSM programs in three-year cycles as part of the IRP
process. 707 ENO notes, however, in its Reply Brief that it would be willing to extend the
amortization period to up to 10 years, and that this would still result in Rider DSMCR having a
lower rate impact on an NPV basis than the Advisors’ proposed EECR;708 and
WHEREAS, ENO argues that the Advisors’ argument that 7.78% is an overly optimistic
assumption of what the average ratepayer could earn in the market if they were able to keep and
invest the money over the amortization period is unsupported speculation and that the 7.78% is the
same discount rate ENO has historically used when comparing resource alternatives and is
appropriate if demand-side and supply-side resources are to be evaluated on an equal footing.709
ENO argues that the Rider DSMCR is the better cost recovery mechanism for pursuing the
Council’s aggressive DSM goals and implementing its long-term vision, and has a lower rate
impact on customers;710 and
WHEREAS, the Council agrees with the Advisors that DSM expenditures would not
typically meet the requirement for being treated as a regulatory asset; and
WHEREAS, the Council finds that in light of the concerns raised by the parties, ENO has
not presented sufficient evidence of the benefits to customers of its proposal to rate base DSM
expenditures; and
WHEREAS, the second component to be recovered through proposed Rider DSMCR
would be a utility performance incentive that would involve taking the resulting balance

707

Id., quoting Ex. No. ENO-10 at 22.
Id. at 76.
709
Id. at 77.
710
Id. at 78.
708

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 corresponding to the total amount of the investment (as deferred expense) in DSM offerings for a
given PY and the Company being allowed to earn a return at ENO’s pre-tax WACC based on its
allowed ROE, subject to a performance adjustment;711 and
WHEREAS, AAE argues that it is relatively uncommon for a utility to earn a ROR on
DSM expenses, and that rather than being a trend for regulators to grant such treatment, it is merely
a trend in what utilities want to get.712 AAE does support the use of utility performance incentives
as a method for encouraging energy efficiency, but states that the Council should be cautious and
only reward truly good performance.713 AAE also prefers an energy efficiency resource standard
(“EERS”) as a better option than a performance incentive.714 AAE argues that ENO’s proposed
performance incentives are too rich and will provide shareholders a return regardless of the amount
of savings achieved relative to target;715 and
WHEREAS, AAE suggests a meaningful minimum savings threshold below which no
additional earnings are received, such as 80% of the annual target with penalties for poor
performance; a more graduated incentive with more granular steps; and a cap on total incentive
awards;716 and
WHEREAS, the AAE and Sierra Club also argue that the Council should directly state
what performance incentive will be used going forward, and state that they do not object to the
performance incentive proposed by the Advisors in the Advisors’ March 1, 2018 Energy Smart
Plan Recommendations for Program Years 7-9;717 and

711

Ex. No. ENO-10 at 19:19-23; Ex. No. ENO-14 at 26:12-14.
Ex. No. AAE-3 at 39:14-40:7.
713
Id. at 47:18-48:4.
714
Id. at 48:4-7.
715
Id. at 48:8-19.
716
Id. at 49:15-50:5; AAE/Sierra Club Initial Brief at 40.
717
AAE/Sierra Club Reply Brief at 12, citing Advisors Recommendations for Council Consideration Pursuant to
Resolution R-17-623 Re: Unresolved Issues for Energy Smart Program Years 7-9, Docket No. UD-08-02 (Mar. 1,
2018).
712

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 WHEREAS, ENO argues that AAE recommends an unnecessarily punitive performance
incentive mechanism that does not recognize the Council’s Energy Smart framework already in
place. 718 ENO argues that to level the playing field, the incentive mechanism should seek to
approximate what the utility would have earned by investing the same amount of capital in a
traditional asset.719 ENO also argues that AAE’s proposal to penalize ENO by limiting recovery
solely to Energy Smart investments below a predetermined savings threshold, and additionally to
impose a second-step penalty equivalent to the value of foregone cost savings for failing to achieve
the minimum threshold is unreasonable, absent a finding of imprudence in light of the fact that it
is ultimately the Council’s decision as to what ENO implements.720 ENO is, however, amenable
to a more granular framework with smaller “steps.”721 In its rejoinder testimony, ENO proposes
changing the framework such that achieving between 90% and 110% of targeted Energy Smart
savings in a given year would not result in any ROE adjustment while ROE is reduced by 5 basis
points for every 1% below 90% that is achieved, and increased by 5 basis points for every 1%
above 110% that is achieved, with a maximum of up to 100 basis points.722 ENO also states that
there will be a cap on the performance incentive that is used;723 and
WHEREAS, ENO argues that it makes no sense to defer the incentive mechanism
structure, particularly with no guidelines at all around its potential future form, because this would
not provide ENO with the certainty necessary to make DSM a core part of its business or put DSM
on a level playing field with supply-side resources.724 ENO urges the Council to determine the

718

ENO Initial Brief at 121.
Ex. No. ENO-12 at 29:11-13.
720
Ex. No. ENO-13 at 10:2-11.
721
Id. at 10:21-22.
722
Id. at 10:22-11:4.
723
Id. at 33:4:7.
724
ENO Initial Brief at 117.
719

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 appropriate incentive procedure in this docket and not to delay consideration until the Council
considers the specific goals and budgets for future years of Energy Smart in the IRP docket; 725 and
WHEREAS, the Advisors argue that while it is appropriate for a utility performance
incentive to be included in ENO’s compensation for the Energy Smart program, it is more
appropriate for such mechanisms to be determined along with the Energy Smart program designs,
budgets and savings goals than in a rate case, and the Advisors continue to recommend that the
performance incentive be addressed in that proceeding rather than in this case. 726 The Advisors
argue that ENO’s argument that the Council should determine the appropriate utility incentive
procedure in this Docket and not delay consideration is without merit, since the Council will be
considering the implementation plan for the next Energy Smart program years in the third quarter
of this year;727 and
WHEREAS, the Council agrees that the appropriate performance incentive for the Energy
Smart program is best considered in the Energy Smart docket alongside the targets and budgets set
for the program; and
WHEREAS, in light of the anticipated timing of the Council’s consideration of the Energy
Smart docket, the Council finds that uncertainty regarding the performance incentive is unlikely
to exist for an unreasonably long period of time; and
WHEREAS, the third component to be recovered through Rider DSMCR would be LCFC,
adjusted each year based on the incremental (or decremental) change to ENO’s DSM investment
and resulting projected energy savings.728 ENO proposes to calculate projected annualized LCFC
amounts the same way that LCFC has been calculated historically, albeit with updated values

725

Ex. No. ENO-12 at 23:6-9.
Advisors’ Initial Brief at 82.
727
Id.
728
Ex. No. ENO-10 at 20:1-6.
726

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 reflecting the outcome of the rate case.729 ENO proposes to calculate the total projected annualized
LCFC amount for the upcoming year, which would be recovered concurrently through the Rider
DSMCR (but not through the regulatory asset) and would be subject to a true-up relative to actual
results that would occur in the following year. 730 ENO argues that it is important to provide
recovery of LCFC in order to put DSM offerings and more traditional, supply-side resources on
more equal footing;731 and
WHEREAS, AAE opposes ENO’s proposal to collect LCFC, and argues that a utility that
has a decoupling mechanism will automatically recover the net effect of any energy or demand
reduction resulting from its program, along with changes in energy and demand resulting from
matters outside its influence or control, and therefore ENO does not need LCFC. 732 AAE also
argues that an LCFC is not necessary to level the playing field between demand-side and supplyside resources because demand-side resources are more appealing than supply side resources due
to the lack of any need for the utility to have any ongoing role in maintenance or operation of those
resources.733 AAE recommends that the Council reject the LCFC in favor of a simple decoupling
mechanism that AAE proposes 734 and arguing that a full decoupling mechanism is a superior
mechanism to a lost revenue adjustment.735 AAE and Sierra Club also point out that ENO has
failed to explain several aspects of its LCFC proposal, including the definition of adjusted gross
margin and how reconciliation will occur;736 and

729

Id. at 28:3-5.
Id. at 28:8-12; Ex. No. ENO-14 at 25:11-18.
731
Id. at 28:18-20.
732
Ex. No. AAE-1 at 30:21-31:4; AAE/Sierra Club Initial Brief at 33.
733
Ex. No. AAE-1 at 33:6-34:21.
734
Id. at 38:16-17.
735
Ex. No. AAE-3 at 39:8-13; AAE/Sierra Club Initial Brief at 34-35.
736
AAE/Sierra Club Initial Brief at 36-37.
730

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 WHEREAS, AAE also points out that lost revenues are not themselves equivalent to
under-recovery of fixed costs for the utility because other factors, such as weather, customer
growth, economic growth, or off-system sales may provide a balancing effect.737 AAE also argues
that there is strong evidence that decoupling is generally associated with better energy efficiency
outcomes than LCFC;738 and
WHEREAS, the Advisors oppose the inclusion of LCFC in any cost recovery
mechanism,739 noting that ENO’s own witness, Dr. Faruqui states:
To address the issue of LCFC, regulators in many states allow utilities to recover
the LCFC that is specifically associated with reduced energy sales due to the
utility’s DSM investments. Recovery of DSM-specific LCFC is most commonly
achieved concurrently through a dedicated DSM rider based on a forward-looking
period. In some states, regulators have instead chosen to fully decouple the utility’s
revenues from its energy sales (known as “full revenue decoupling”).740
WHEREAS, in Resolution No. R-16-103, the Council directed ENO to file a proposal for
full decoupling in this Combined Rate Case.741 Therefore, the Advisors argue, the inclusion of
LCFC in a DSM-specific rider is not appropriate, rather, any erosions in fixed costs should be
considered in the annual FRP review and Decoupling mechanism;742 and
WHEREAS, Air Products, however, argues that to the extent the Council allows ENO to
recover any LCFC costs, those costs should be recovered as part of the EECR or DSMCR
mechanism and not as part of the FRP and decoupling mechanisms in order to keep those costs
associated with the programs and customers that cause them.743 Air Products notes that if the

737

Ex. No. AAE-3 at 42:15-18.
Id. at 44:8-46:7.
739
Ex. No. ADV-3 at 76:5-6.
740
Ex No. ENO-14 at 12:17-13:2 (emphasis added).
741
Resolution No. R-16-103 at 21.
742
Ex. No. ADV-3 at 76:6-7; Advisors’ Initial Brief at 78.
743
Ex. No. AP-4 at 12:13-13:14; Air Products’ Initial Brief at 34; Air Products’ Reply Brief at 5.
738

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 Advisors’ proposal is to include LCFC in FRP evaluations and decoupling mechanism using the
same allocation used by the EECR, it may address Air Products’ concern;744 and
WHEREAS, Air Products also argues that energy efficiency programs increase the
utility’s average cost of supplying service, resulting in an increase in rates, and that such programs
can only be regarded as beneficial to nonparticipants of the end result were to be rates lower than
they otherwise would have been, as evidenced by a Ratepayer Impact Measure test of 1.0 or
greater.745 Air Products argues that such an outcome is rare, and there is no evidence to support
the RIM test results for the energy efficiency program being in excess of 1.0, therefore
nonparticipants do not benefit from the energy efficiency programs;746 and
WHEREAS, ENO argues Air Products’ comments regarding the cost-effectiveness of
energy efficiency are misplaced, because the Council has established rules and a process for
assessing the cost effectiveness of each PY’s portfolio of DSM offerings and their associated
budgets;747 and
WHEREAS, ENO emphasizes that it is undisputed that LCFC needs to be addressed, it is
just a matter of where, but agrees with the Advisors that if the final design of the FRP incorporates
features that ENO believes adequately address LCFC, then the Company would not need to recover
LCFC amounts in Rider DSMCR or through some other cost recovery mechanism other than the
FRP.748 ENO witness Owens stated in his rebuttal testimony that the Advisors’ proposal to make
proforma adjustments to address timely recovery of demand-side management costs could present
a workable solution to the LCFC issue, contingent on agreeing on the specific FRP language. 749

Air Products’ Initial Brief at 34.
Ex. No. AP-4 at 13:15-21.
746
Id. at 14:1-4.
747
Ex. No. ENO-13 at 12:7-9.
748
Ex. No. ENO-12 at 10:13-18.
749
Ex. No. ENO-13 at 7:10-11; see also, ENO Reply Brief at 80.
744
745

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 ENO does not, however, believe that the AAE’s decoupling proposal could adequately address
LCFC because it would delay recovery of the lost revenues by at least a year. 750 ENO opposes
methods of cost recovery that would cause ENO to be always a year or more behind in the recovery
of fixed costs attributable to Energy Smart-related DSM investments;751 and
WHEREAS, the Council agrees with the Advisors that the erosion of any fixed costs is
best considered in the annual FRP review and Decoupling mechanism; and
WHEREAS, finally, the fourth component included in ENO’s proposed Rider DSMCR
would be an adjustment resulting from a true-up that will occur once a year based on prior year
actual results.752 ENO proposes that Rider DSMCR rates be set only once a year and take effect
at the beginning of each PY with the first billing cycle. 753 ENO also argues that the EECR may
over or under-recover Energy Smart costs if it does not include some form of annual true-up
mechanism within the EECR Rider, because of EECR revenues in any given year were less than
the amount of Energy Smart program costs, but the FRP evaluation results were within the
bandwidth, no rate adjustment would occur, and ENO would not recover all of the Energy Smart
costs for that year;754 and
WHEREAS, the Advisors recommend that the EECR Rider be utilized as the long-term
funding mechanism for the Energy Smart program and argue that ENO has failed to demonstrate
that its proposed Rider DSMCR would be more beneficial to ratepayers than the EECR Rider.755
The Advisors argue that compared to ENO’s arguments for its proposed DSMCR, the EECR
(i) does represent a permanent funding mechanism, (ii) can track DSM investments and cost

750

Ex. No. ENO-13 at 7:17-8:5.
Ex. No. ENO-12 at 11:4-11 and 12:11-19.
752
Ex. No. ENO-10 at 20:16-18.
753
Id. at 20:18-19.
754
Ex. No. ENO-12 at 23:10-17.
755
Advisors’ Initial Brief at 80.
751

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 recovery through annual filings, (iii) provides stability by ensuring funding will be available,
(iv) provides a clear path and flexibility to incorporate changes to DSM, (v) does not have to appear
as a separate line item on customers’ bills, and (vi) represents less of a financial burden to
ratepayers than DSMCR, since the nominal cost to ratepayers with DSMCR would be higher
including ENO’s return on the regulatory asset;756 and
WHEREAS, the Advisors assert that the EECR Rider will provide ENO with a reasonable
opportunity to recover its DSM investments and757 that lost revenues due to the Energy Smart
program should be addressed through the decoupling and FRP mechanisms, rather than the
proposed DSMCR rider.758 The Advisors argue that the purpose of allowing lost revenue recovery
is not to guarantee that the utility earns exactly as much money as it would if DSM was not
implemented, rather it is to ensure that the utility has a fair and reasonable opportunity to earn its
authorized revenue requirement.759 Further, the Advisors state, to the extent that increased sales
due to weather or other factors offsets revenues lost due to the implementation of energy efficiency
measures, there is simply no need to further compensate ENO;760 and
WHEREAS, the Council finds that the EECR Rider is the appropriate long-term funding
mechanism for the Energy Smart program; and
DEMAND RESPONSE MECHANISMS
WHEREAS, both ENO and BSI propose rates that would allow customers to be paid for
actively reducing their load during key times; and
(1)

ENO Proposal - Extend MVLMR and MCDRR to All Customers

756

Id.
Id. at 81.
758
Id.
759
Id.
760
Id.
757

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 WHEREAS, ENO proposes to extend two of the riders previously in effect in the Algiers
territory to all of its customers, the Market Valued Load Modifying Rider (“MVLMR”) and the
Market Valued Demand Response Rider (“MVDRR”).761 ENO explains that these riders provide
the opportunity for qualified retail customers, or qualified aggregators of retail customers, to act
as a load modifying resource (MVLMR) or a demand response resource (MVDRR), consistent
with MISO-prescribed standards and requirements;762 and
WHEREAS, the Advisors note that demand response and load modifying resources are
important facets of the Council’s policy to expand demand side management in New Orleans,763
and because these riders have already been implemented in Algiers, and ENO has experience
administering the Riders; the Advisors support ENO’s proposal to expand the MVLMR and
MVDRR to ENO’s full service territory. 764 The Advisors recommend, however, that because
many customers will be unable to perform a cost benefit analysis of the investment they make by
volunteering in the riders, ENO should provide support, such as providing a cost estimate from the
MISO tariff and other related information regarding cost, to customers to help them make more
informed decisions as to whether to voluntarily participate;765 and
WHEREAS, the AAE and Sierra Club also support the extension of the MVLMR and
MVCRR riders to its full service territory.766 They support the suggestion that ENO be required
to provide some kind of support to potential participants, including a cost-estimate so potential
customers understand the programs and know what they are getting into.767 AAE and Sierra Club
also propose, for the first time in their Reply Brief, that the MVLMR rider be amended to (a) make

761

Ex. No. ENO-55 at 30.
Ex. No. ADV-3 at 64:13-18.
763
Ex. No. ADV-3 at 64:18-20.
764
Advisors Initial Brief at 120-121.
765
Ex. No. ADV-3 at 65:4-9; Advisors Initial Brief at 121.
766
AAE/Sierra Club Reply Brief at 21-22.
767
AAE/Sierra Club Reply Brief at 22.
762

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 it a multi-year commitment so that it is a useful planning resource for ENO; (b) increase the
compensation towards long-term avoided costs to recognize the fact that it is a useful planning
resource, and (c) allow customers to participate through aggregators of retail customers;768 and
WHEREAS, no party opposes the extension of ENO’s MVLMR and MVDRR riders to
ENO’s full service territory; and
WHEREAS, the Council notes that AAE and Sierra Club’s proposed changes are not
supported by any evidence in the record and were proposed for the first time in their Reply Brief
such that no other party has had opportunity to probe or respond to the proposals; and
WHEREAS, the Council agrees that the expansion of the demand response riders supports
the Council’s policy to expand demand-side management in New Orleans; and
WHEREAS, the Council finds it reasonable to require ENO to add a component of
customer support, including the provision of cost estimates to customers to be reasonable; and
(2)

BSI CLEP Proposal

WHEREAS, BSI proposes the adoption of three Customer Lowered Energy Pricing
(“CLEP”) rates, a CLEP residential rate, a CLEP non-residential rate, and CLEP community
solar.769 CLEP community solar is discussed above along with ENO’s community solar proposal.
Under the proposed CLEP rates, a customer either earns a payment or incurs a charge every five
minutes (called “CLEP5”).770 The customer earns a CLEP5 payment for each five minute period
in which either (a) the customer purchases electricity from ENO when the current MISO price of
energy is lower than ENO’s cost to produce energy; or (b) the customer sells electricity to ENO
when the current MISO price of energy is higher than ENO’s cost to produce energy. 771

768

AAE/Sierra Club at 22.
Ex. No. BSI-1 at 6:13-16.
770
Ex. No. BSI-1 at 12:1-9.
771
Ex. No. BSI-1 at 12:1-9.
769

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 Conversely, the customer would incur a CLEP5 charge within each five-minute period that the
customer either (a) purchases electricity from ENO when the MISO price for electricity is higher
than ENO’s cost to produce energy or (b) sells electricity to ENO when the current MISO price
for energy is lower than the ENO’s cost to produce electricity;772 and
WHEREAS, customers would also earn monthly payments or incur monthly charges
(called CLEPm) for providing or demanding power at nearly the same times the utility experiences
its annual peak demand.773 The CLEP5 payments and charges are summed monthly and added to
the CLEPm payment or charge to produce a credit or charge on the customer’s monthly bill.774 It
does not replace and otherwise has no effect on the customer’s regular monthly bill under the
customer’s regular rate.775 If CLEP results in a payment to the customer that exceeds the charges
the customer owes on its monthly bill, the customer receives a monetary credit;776 and
WHEREAS, BSI states that CLEP payments benefit non-CLEP customers because “Every
CLEP transaction will include a 5% service charge to be collected by the utility. Thereafter, some
portion of the 5% service charge can be distributed to all ENP customers after deducting ENO’s
administrative costs according to the Council’s rulemaking.”777 BSI also states that appropriate
use of the CLEP rate by a customer will lower the average cost of electricity ENO incurs, while a
CLEP customer that fails to modify their behavior and makes purchases or sales at the wrong time
will only cause an increase in their own electricity bill.778
WHEREAS, BSI argues that its CLEP rate would lower ENO’s true cost of service to
supply power, enhance reliability, appropriately assign demand charges to customers with higher

772

Ex. No. BSI-1 at 12:9-13.
Ex. No. BSI-1 at 12:17-19.
774
Ex. No. BSI-1 at 16:11 and 17:1.
775
Ex. No. BSI-1 at 14:17-22.
776
Ex. No. BSI-1 at 15:15-17.
777
Ex. No. BSI-1 at 22:9-12.
778
Ex. No. BSI-1 at 22:18-23:4.
773

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 than usual demand, correctly reflects residential customers’ impact on demand and energy use,
account for entities with a peak that differs from ENO’s peak, provide economic benefit to
customers who have heavily invested in storage, provide credits to EV owners who charge off
peak, provide a financial incentive to install batteries, and generally cause customers to make
choices that will lower demand;779 and
WHEREAS, the Advisors argue that whether the CLEP proposal will actually produce
these benefits is uncertain.780 In addition, the Advisors find the design of CLEP to be extremely
complicated and not one that customers will easily be able to navigate. 781 The Advisors believe
customers are unlikely to be able to determine the relative positions of ENO and MISO’s costs of
producing electricity in five-minute increments.782 The Advisors point out that BSI is clear that
CLEP customers who fail to successfully adapt their behavior to change as the relative positions
of ENO and MISO’s costs change would see an increase in their electricity bills.783 ENO opposes
the CLEP proposal and argues that it appears to be substantially the same as to the proposal already
rejected by the Council in Resolution Nos. R-16-106 and R-17-100.784 The Advisors believe that
the most likely outcome of implementing CLEP would be that most CLEP customers experience
difficulty in managing their energy use and production in five minute increments, resulting in
increased electricity bills and frustration.785 Therefore, the Advisors do not recommend that CLEP
be adopted by the Council, particularly in light of the demand response opportunities available
under Riders MVLMR and MVDRR;786 and

779

Ex. No. BSI-1 at 23:16-26:4.
Advisors Initial Brief at 122.
781
Advisors Initial Brief at 122-123.
782
Advisors Initial Brief at 122-123.
783
Advisors Initial Brief at 123.
784
Ex. No. ENO-12 at 50:7-11.
785
Advisors Initial Brief at 123.
786
Advisors Initial Brief at 123.
780

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 WHEREAS, the Advisor argue that as BSI notes, there are two primary ways that a
customer can benefit from CLEP, the first would be by investing in programmable appliances and
programming those appliances to run in a manner that takes advantage of CLEP pricing. 787 The
second would be by hiring an aggregator to assist them.788 The Advisors agree with BSI that, at
least initially there will be few, if any, aggregators able to provide such a service, 789 and the
Advisors note that it will take an extensive level of expertise in both ENO’s pricing structure and
MISO markets and will require access to real-time information about the price differentials
between the two, in five-minute increments, as well as fairly extensive control over the consumer’s
consumption of electricity in five-minute increments, for an aggregator to effectively help
customers make money by participating in CLEP;790 and
WHEREAS, the Advisors argue that as to the use of programmable appliances, BSI posits
that programming them to always run at the same time of day would be sufficient to allow a
customer to profit from CLEP, but while this may generally work under average circumstances, it
may not be able to shield customers from being penalized under CLEP when there are unexpected
developments in the MISO market, such as unanticipated generator outages or capacity
shortages.791 Thus, the Advisors note, there is no guarantee that a customer will only get payments
from CLEP and not incur occasional penalties.792 As BSI notes, the electricity bill of a customer
participating in CLEP could either go up, go down, or hardly change.793 The Advisors note that
as homes become increasingly automated over time and the grid becomes modernized and smarter,
it is possible that at some point in the future a CLEP-like model could be adopted that allows smart

787

Advisors Reply Brief at 60, BSI Initial Brief at 36.
Advisors Reply Brief at 60, BSI Initial Brief at 36.
789
Advisors Reply Brief at 60, BSI Initial Brief at 36.
790
Advisors Reply Brief at 60-61.
791
Advisors Reply Brief at 61.
792
Advisors Reply Brief at 61.
793
BSI Initial Brief at 35.
788

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 devices and Artificial Intelligence to effectively manage energy use for the customer so that
customers can benefit from CLEP with much less effort and investment, and at such time, it may
make sense for the Council to consider such a model.794 However, the Advisors argue, that time
has not yet come, as matters stand today, the CLEP model is impractical to implement, and should
be rejected by the Council;795 and
WHEREAS, ENO supports the Advisors’ arguments in favor of rejecting the BSI CLEP
proposal. 796 ENO also points out that while CLEP participants would be engaging in energy
transactions every 5 minutes, the data from AMI meters is recorded and transmitted in 15-minute
increments, thus, it does not appear that it is possible to implement CLEP without significantly
altering the configuration of AMI deployment, which is presently underway; 797 and
WHEREAS, BSI also requests that the Council appoint a Load Flexibility and Time-ofUse Rate-Design Working Group to begin work immediately in designing and implementing
CLEP that would include key stakeholders, ENO, the Council’s utility Advisors, residential,
commercial, municipal, water utility, and industrial customers, environmental justice and
conservation communities and nationally recognized experts on load flexibility, and TOU rates
and TOU rates, and that the Council should hire an independent consultant to advise the Working
Group as well;798 and
WHEREAS, although BSI argues that CLEP fulfills nearly every regulatory purpose and
goal of the Council as well as addressing Global Warming and Sea Level Rise and will lower rates
to all customers, the Council finds these claimed benefits to be speculative in nature and the overall

794

Advisors Reply Brief at 61.
Advisors Reply Brief at 61.
796
ENO Reply Brief at 84-85.
797
ENO Reply Brief at 85.
798
BSI Reply Comments at 8.
795

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 design of CLEP to be overly complicated for consumers to understand while requiring a
considerable amount of either programmable equipment, or skill and expertise either by the
customer or an aggregator to be practical to implement at this time; and
WHEREAS, having rejected the CLEP proposal, the Council also rejects as moot BSI’s
request for a the establishment of a working group to design and implement the CLEP proposal;
and

EV CHARGING INFRASTRUCTURE
WHEREAS, ENO proposes two different concepts designed to expand access to EV
charging infrastructure in New Orleans and which would complement an offering currently
available to residential customers.799 ENO also proposes a separate initiative involving rebates for
customer-owned EV charging infrastructure;800 and
(1)

Rider Schedule Electric Vehicle Charging Infrastructure (“EVCI”)

WHEREAS, the first concept, available to non-residential customers, would involve ENO
constructing, owning, and operating EV charging infrastructure on customer-owned property.801
In return, the customer would pay a fixed amount each month tied to a percentage specified under
the proposed Rider Schedule EVCI and the installed cost of the equipment, less (1) the value of a
30% tax credit available from the State of Louisiana and (2) an estimated level of near-term, nonfuel revenue.802 ENO argues that there are several benefits to non-participating customers: (1) new
revenues from charging usage helps recover fixed costs on ENO’s system and other costs, and thus
helps control rates for all of ENO’s customers; (2) only the participating customer is paying for
799

Ex. No. ENO-55 at 40.
Ex. No. ENO-10 at 58:5-7.
801
Ex. No. ENO-55 at 40; Ex. No. ENO-10 at 58:8-14.
802
Ex. No. ENO-55 at 40; Ex. No. ENO-10 at 59:9-12.
800

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 the dedicated EV charging facilities; (3) to the extent the customer uses the program to provide
public EV charger access (such as at a shopping mall or parking lot), non-participants who live in
New Orleans and own or lease an EV would benefit from increased access; and (4) expanding
access to EV charging infrastructure would provide important environmental and other public
policy benefits.803 ENO states that customers who take advantage of this program will be able to
provide access to the chargers to their employees, customers, and/or tenants without issue,
including being able to charge a fee for use of the charger;804 and
WHEREAS, the Advisors state that ENO’s Rider EVCI proposal is properly
constructed.805 The Advisors find that the rider would be entirely voluntary to ratepayers and
would not impose any material costs on non-participant ratepayers.806 The proposed Rider EVCI
is consistent with the theory underlying Rider AFC, which the Council has already approved. 807
There appears to be no reason to expect that Rider EVCI would prevent ratepayers from funding
their own EV charging stations; a commitment under Rider EVCI is entirely voluntary; however,
the Council may wish to make clear to ENO that similar new meter installations are appropriate
for ratepayer-funded EV charging stations, subject to all of ENO’s service standards. 808 The
Advisors recommend that the Council approve Rider ECVI-1 as proposed by ENO, and
specifically note that it is not to be applied prejudicially to ratepayers who choose to construct EV
charging stations outside of Rider EVCI in terms of vendor selection, provision of related electric
service, and financing services;809 and
WHEREAS, no party opposes Rider EVCI; and

803

Ex. No. ENO-10 at 60:18-61:4.
Ex. No. ENO-10 at 64:19-21.
805
Advisors Initial Brief at 135, Ex. No. ADV-6 at 94:10-11.
806
Advisors Initial Brief at 135, Ex. No. ADV-6 at 94:11-12.
807
Advisors Initial Brief at 135, Ex. No. ADV-6 at 94:12-14.
808
Advisors Initial Brief at 135, Ex. No. ADV-6 at 94:19-95:1.
809
Advisors Initial Brief at 135-136, Ex. No. ADV-6 at 95:19-96:2; Ex. No. ADV-2 at 50:6-8.
804

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 WHEREAS, the Council finds EVCI to be reasonable; and
(2)

Public EV Charging Infrastructure Offering

WHEREAS, ENO’s second proposal would be available to public institutions and would
involve ENO constructing, owning, and operating EV charging infrastructure solely for public use
at a handful of key locations in New Orleans.810 ENO would collaborate with City officials to
determine optimal locations for the EV chargers, which could include downtown City-owned
right-of-way, public libraries and schools, parks, and other recreational areas.811 ENO is proposing
to invest up to $500,000 over the next 24-30 months to build out EV charging infrastructure on
public property that would be made accessible to electric vehicle drivers.812 ENO is proposing to
recover the capital investment and related expenses in retail rates through the normal ratemaking
process;813 and
WHEREAS, ENO is proposing that no additional fee or charge be levied on any EV driver
for using the charging equipment regardless of where the EV charger is located relative to a
customer’s meter.814 ENO explains that the City or other public entity that owns the property may
charge for parking, but ENO would not impose an additional fee or charge related to using the EV
charger or the electricity dispensed by the equipment used to charge the EV’s battery. 815 ENO
anticipates that the cost of the electricity provided in this manner would be small, and for locations
where the charging equipment is not behind the customer’s meter, ENO proposes that the value of
electricity not being billed to the EV drivers would be reflected in ENO’s FAC in the same way

810

Ex. No. ENO-55 at 40; Ex. No. ENO-10 at 58:15-15-17.
Ex. No. ENO-55 at 40-41; Ex. No. ENO-10 at 58:17-20.
812
Ex. No. ENO-55 at 41; Ex. No. ENO-10 at 58:22-23.
813
Ex. No. ENO-55 at 41; Ex. No. ENO-10 at 67:16-19.
814
Ex. No. ENO-10 at 68:3-5.
815
Ex. No. ENO-10 at 68:5-8.
811

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 that unaccounted-for energy from line losses and other forms of non-technical losses are treated
today;816 and
WHEREAS, the Advisors support EV charging stations installed behind the ratepayer
meter, where the ratepayer pays ENO for the electricity consumed and then makes a decision as to
whether and how much to charge users of the EV charging stations to charge their cars. 817 The
Advisors support the ability of such ratepayers to offer amenities, such as free EV charging, that
the ratepayer deems valuable to their business or purpose, and do not view free EV charging
offered in this context as anti-competitive;818 and
WHEREAS, the Advisors, however, do believe that ENO’s proposal to build some
charging stations in front of the customer meter (where use is not measured or paid for) and to
offer charging for free to EV drivers with the costs rolled into ENO’s rates and borne by all
ratepayers could be problematic.819 First, the Advisors argue, the generally accepted regulatory
ratemaking principle of cost causation does not support socializing one ratepayer group’s (i.e., EV
charging station users) costs among other groups (i.e.¸ all other ratepayers), even if the subsidy is
small, it is not appropriate to require other ratepayers to pay for an EV charger customer’s
electricity.820 Second, free EV charging offers an incentive for EV owners to avoid charging where
energy is not free, such as at home.821 Further, the Advisors express concern that since EV owners
reasonably could be expected to prefer free EV charging stations over those that charge a fee, non-

816

Ex. No. ENO-10 at 68:8-15.
Advisors Initial Brief at 137, Ex. No. ADV-6 at 100:12-15.
818
Ex. No. ADV-6 at 100:12-15.
819
Advisors Initial Brief at 137.
.820 Advisors Initial Brief at 137, Ex. No. ADV-6 at 99:4-7. Advisors’ witness Watson calculates the amount to be
socialized in this manner as possibly being as high as $64,432, ENO witness Owens argues that it would be only a
fraction of that amount. Ex. No. ENO-12 at 46:3-21.
821
Advisors Initial Brief at 137, Ex. No. ADV-6 at 99:7-9.
817

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 ENO EV charging station providers could be deterred from installing EV charging stations near
an ENO free EV charging station;822 and
WHEREAS, the Advisors argue that adding EV charging stations is consistent with the
Council’s goals and policies regarding Smart Cities and environmental benefits for New Orleans;
however, rather than having the Council decide an issue that could have such a significant impact
upon the market for EVs in New Orleans as part of this rate case, the Advisors initially recommend
that the issue of whether ENO should install EV chargers and/or offer free charging to the public
should be taken up in the EV Docket, UD-18-01, where stakeholders with an interest in
encouraging EVs in New Orleans will have better opportunity to participate in the discussion;823
and
WHEREAS, with respect to the Advisors’ proposal that the issue be considered not in this
proceeding, but in UD-18-01, ENO proposes that the issue of ENO’s investment be separated from
the issue of where to locate the EV chargers, and that Docket UD-18-01 might be the forum in
which ENO, the City and the stakeholders could collaborate as to where to locate the estimated 30
to 50 Level 2 chargers that ENO would construct and operate.824 The Advisors agree with ENO’s
proposal and recommend that ENO be allowed to proceed with its proposed $500,000 investment
with siting of the charging stations to be considered as part of Council Docket No. UD-18-01.825
WHEREAS, the Advisors explain that the proposal to authorize ENO to invest up to
$500,000 in public EV charging infrastructure in the instant proceeding and then use Council
Docket No. UD-18-01 to engage stakeholders where best to cite ENO’s proposed EV chargers is
reasonable and mitigates the Advisors’ concerns, particularly in light of Council’s stated interest

822

Advisors Initial Brief at 138, Ex. No. ADV-6 at 100:8-10.
Advisors Initial Brief at 138, Ex. No. ADV-6 at 100:16-102:3.
824
ENO Initial Brief at 181, and Ex. No. ENO-12 at 48:1-11.
825
Advisors Initial Brief at 138-139, Ex. No. ADV-8 at 51.
823

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 in promoting environmental benefits, the limited scope of ENO’s specific investment proposal,
and the minimal amount of socialized costs. 826 The Advisors, therefore, recommend that the
Council authorize ENO’s proposed investment of up to $500,000 in public EV charging
infrastructure that would provide free EV charging services at roughly 30-50 locations and
consider any stakeholder input as to the siting of such locations in Council Docket No. UD-1801;827 and
WHEREAS, the Council finds the compromise proposed by ENO and the Advisors to be
reasonable; and
(3)

Rebate for EV Charger Installation

WHEREAS, ENO also proposes to continue with its Electric Technology initiative
(“eTech”) under which it provides a $250 rebate to qualifying customers to partially offset the
costs they incur to install Level 2 EV chargers at their home or business. 828 ENO argues that the
program is beneficial, because it allows ENO to know which of its customers have installed a
Level 2 charger, and to periodically get data about impacts on electric load including hours of the
day, possible frequency of charging, and so forth. 829 Knowing where EV chargers are located on
its system and being able to perform analysis could help with grid planning and maintain reliability
and also help inform how grid modernization can help to accommodate increased penetration of
EVs.830 ENO could also periodically survey participating customers to better understand their
real-world experience as EV drivers in New Orleans, what actions they would like to see taken by
ENO and/or the City to expand access, etc.;831 and

826

Advisors Initial Brief at 139, Ex. No. ADV-8 at 51:9-14.
Advisors Initial Brief at 139, Ex. No. ADV-8 at 51:18-52:3.
828
Ex. No. ENO-10 at 69:9-12.
829
Ex. No. ENO-10 at 69:16-19.
830
Ex. No. ENO-10 at 69:19-70:2.
831
Ex. No. ENO-10 at 70:3-70:6.
827

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 WHEREAS, the Advisors also support ENO’s proposed EV charger rebate program.832 A
Level 2 charger may be considered a load-modifying resource when used off-peak, which can
generate benefits for all ratepayers reflected in MISO charges and credits.833 Because Level 2
chargers can be viewed as DSM and, when used off-peak, are likely to utilize less carbon-intensive
production resources, the Advisors believe that encouraging Level 2 EV chargers through a rebate
program is consistent with the Council’s policies on energy efficiency and environmental
benefits. 834 The Advisors also believe that because EV chargers may be considered energy
efficiency or DSM measures, it would be most appropriate to fund them through the Energy Smart
Program, going forward, but recognizing that the earliest such a mechanism would be in place
would be for Energy Smart Program Year 2020, the Advisors recommend that in the interim, the
Council authorize ENO to continue its $250 per Level 2 charger rebate program, and that any
related cost recovery proposal be considered through the FRP mechanism;835 and
WHEREAS, ENO argues that the eTech efforts are efforts at electrification (conversion
of equipment that uses fossil fuel to electric), which ultimately increases electricity usage, and
therefore should not be considered energy efficiency measures and funded through the Energy
Smart program.836 ENO argues that the costs should be recovered through normal ratemaking;837
and
WHEREAS, ENO and the Advisors appear to be in agreement that the eTech program
should continue, no party opposes it, and it is consistent with the Council’s interest in fostering
EV adoption in New Orleans. The Council finds that the eTech program should continue; and

832

Advisors Initial Brief at 140.
Ex. No. ADV-6 at 96:16-97:1.
834
Ex. No. ADV-6 at 97:1-4.
835
Ex. No. ADV-6 at 97:6-98:5.
836
Ex. No. ENO-12 at 49:3-16.
837
Ex. No. ENO-12 at 49:16-18.
833

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 WHEREAS, the Council finds that it may be advantageous to ENO’s customers to have
the eTech offering conveniently included within the Energy Smart program, and so agrees with
the Advisors that the eTech rebate should be part of that program. However, the Council
appreciates ENO’s concern that the measure could increase a customer’s overall energy use, rather
than decrease it. To that end, the Council finds that it would be reasonable in the consideration of
the design of the Energy Smart Implementation Plan for PY 10-12, for the parties to develop a
method of evaluating the success of the eTech program separate and apart from the kWh savings
goals of the other Energy Smart program measures, such that increases energy usage related to the
eTech program does not count against ENO’s ability to achieve the kWh and any kW savings goals
established for Energy Smart PY 10-12; and
SERVICE REGULATION AMENDMENTS
WHEREAS, ENO proposes certain minor modifications to its Service Regulations to
reflect current practices, add new definitions, requirements and modifications necessary to reflect
the changing nature of service (such as AMI, and the new offerings).838 ENO states that such
minor modifications include changes such as updating listings for ENO’s website, updating hours
of Customer Service centers, and job titles for certain employees, updating certain definitions to
reflect AMI deployment, and language that separately references East Bank and West Bank
customers, and eliminating outdated or duplicative language, as well as changes reflecting changes
to the nature of service due to AMI deployment, broadening the definition of “written
Communications” to reflect digital communications, and various other modifications reflecting the
changing nature of utility service and new customer offerings;839 and

838
839

Ex. No. ENO-6 at 59:4-9.
Ex. No. ENO-6 at 59:18-62:6.

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 WHEREAS, most of these proposed changes are unopposed by the parties. The Council
finds the unopposed proposed changes to be reasonable; and
WHEREAS, one proposed change was objected to by the Air Products and the Advisors,
specifically, the proposed change to Section 11 Continuity of Service, which would have changed
ENO’s responsibility for loss or damages caused by the failure or other defects of service, which
both Air Products and the Advisors objected to as inappropriate; 840 and
WHEREAS, in its Reply Brief, ENO stated that it does not object to Air Products’
recommendation that ENO’s proposed change to the Continuity of Service provision in the Service
Regulations not be adopted (though ENO objected to the Advisors’ characterization of the effect
of the provision);841 and
WHEREAS, the Council finds the proposed changes to the Service Regulations, except
for the proposed change to Section 11 Continuity of Service, to be reasonable. The Council rejects
the proposed change to Section 11 Continuity of Service; and
City of New Orleans Billing Issues
WHEREAS, CCPUG witness Baron recommends that the Council require ENO to establish a
working group, following completion of the rate case to address billing issues. ENO opposes this
recommendation, noting that CCPUG did not identify the aspects of billing that the City claims to
be at issue, and recommends that instead the City work with its account representative to address
any billing issues. The Advisors agree that a working group likely is not necessary to resolve the
City’s concerns, and are willing to work with the City and ENO to assist in resolving these
concerns to the City’s satisfaction. CCPUG is supportive of the Advisors’ suggestion, but still
urges the formation of a working group; and

840
841

Ex. No. AP-3 at 25:18-19, Air Products Initial Brief at 44, Advisors Initial Brief at 144.
ENO Reply Brief at 118.

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 WHEREAS, the Council finds it unnecessary to establish a formal working group to address the
City’s issues at this time, but directs its Advisors to work with the City and with ENO to resolve
the City’s billing issues; and
TAX BENEFITS RELATED TO AMI
WHEREAS, as part of the AMI deployment ENO must retire certain related existing plant,
such as meters, prior to its full recovery through depreciation (“Stranded Plant”).842 The Advisors
note that the retirement of this Stranded Plant is associated with ENO’s per-book recording of
ADIT liabilities.843 In its Application, ENO incorrectly removed ADIT related to Stranded Plant
from rate base in the amounts of $6,227,006 and $823,146 for electric and gas respectively.844
Intervenors did not comment on ENO’s exclusion of this ADIT from its rate base; and
WHEREAS, the Advisors recommend that ENO’s rates should reflect the economic
benefit it enjoys due to cost-free capital. Out of an abundance of caution for ENO’s unspecified
“potential violations” of IRS normalization rules, an appropriate mechanism to recognize ENO’s
cost-free capital is a regulatory liability.845 As the economic benefit to ENO of Stranded Plant
ADIT is undisputed, the Advisors recommend the Council recognize the benefit to ENO of costfree capital and direct ENO to create regulatory liabilities in the amount of $6,227,006 and
$823,146 for electric and gas respectively and include those liabilities in ENO’s regulatory rate
base;846 and
WHEREAS, the Council finds that the Advisors’ proposal is reasonable; and

842

Ex. No. ADV-6 at 57:1-3, Advisors Initial Brief at 147.
Advisors Initial Brief at 147.
844
Ex. No. ADV-6 at 58, 11-13, Advisors Initial Brief at 147.
845
Ex. No. ADV-8 at 37:2-3, Advisors Initial Brief at 148.
846
Ex. No. ADV-8 at 37:10-13, Advisors Initial Brief at 148.
843

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 MISCELLANEOUS ISSUES
(1)

Error in ENO’s Calculation of Electric Taxes

WHEREAS, in response to discovery in the instant proceeding, ENO has acknowledged an error
in its calculation of electric taxes, which the Advisors estimate and present correcting adjustments in the
below table; and
Advisor Adjustment ADV06 Period II
Account

Debit

410101

$141,633

190221

Credit

$141,633

410120

$22,872

190222

$22,872

WHEREAS, the Council finds that ENO should correct for this error as part of its compliance
filing; and

(2)

ENO’s $1/Year Per Gas Meter Gas Research and Development Charge

WHEREAS, ENO has proposed a $1 per year per gas meter gas research and development
charge to fund ENO’s participation in certain industry technology development groups; and
WHEREAS, the Advisors testified that, while such expenditures may involve energy
efficiency and environmental benefits, and thus are indicative that they may be prudently incurred
costs, ENO’s proposed per meter charge is not necessary, would constitute single-issue
ratemaking, and such costs should instead be recovered through ENO’s gas base rates; and
WHEREAS, the Council is persuaded by the Advisors’ arguments and finds that, while
ENO’s participation in the groups it discusses may be prudent, a special per-meter charge is not
justified; and

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 OTHER MISCELLANEOUS ISSUES
WHEREAS, ENO is proposing that the Council approve of certain modifications to the
Service Regulations Applicable to Electric and Gas Service by ENO. 847

The proposed

modifications vary in purpose: addressing minor modifications necessary to reflect the changing
nature of service due to innovations such as the impending deployment of AMI and new customer
offerings and billing options the Company proposes to make available to customers848 as well as
the combination of the Algiers and Legacy ENO service territories into a single territory; and
WHEREAS, the Advisors reviewed and had no objection to and no other party objected
to ENO’s proposed changes related to Datalink and other related riders changing due to AMI;849
the updates to fees for certain service schedules;850 and the discontinuation of certain schedules;851
and
WHEREAS, in light of the lack of objection to these proposals by any party, including the
Council’s Advisors, the Council finds these proposals to be reasonable; and
WITHDRAWN PROPOSALS
WHEREAS, ENO proposed a Pre-pay Electric Service (“PES”) Option and Pre-pay Gas
Service (“PGS”) Option (Schedules PES and PGS) which are prepaid billing options for residential
customers.852 ENO’s proposal would be a voluntary billing option enabled by AMI and supporting
technology.853 The Advisors support the development of a pre-pay option for ENO customers.854
However, in its rejoinder testimony, ENO suspended its request for approval of the pre-pay option

847

Ex. No. ENO-55 at 45.
Ex. No. ENO-55 at 45-46.
849
Advisors Initial Brief at 141-142.
850
Advisors Initial Brief at 144-146.
851
Advisors Initial Brief at 146-147
852
Ex. No. ENO-55 at 42.
853
Ex. No. ENO-55 at 42-43; Ex. No. ENO-19 at 4:20-5:2.
854
Advisors Initial Brief at 124.
848

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 due to delays and increased complexity in the integration of the AMI customer web portal with the
Company’s legacy IT and billing systems.855 ENO states that the expected additional integration
and IT development efforts to fully deploy pre-pay service are more complex than were originally
envisioned.856 Because ENO has suspended this request, the Council will not consider ENO’s prepay proposal at this time; and
WHEREAS, in its Application, ENO proposed a voluntary fixed billing option for
residential customers under which, in exchange for paying a premium over what the standard
residential service rate would be, customers receive a monthly fixed bill that will not change over
the contract period. 857 However, in response to the Advisors’ testimony, ENO withdrew this
proposal in its Rebuttal Testimony. 858 Therefore, the Fixed Billing proposal also will not be
addressed by the Council at this time; and
COMPLIANCE FILING
WHEREAS, the Revised Application discusses ENO’s making a compliance filing
resulting from a decision from this proceeding; and
WHEREAS, this resolution does not and is not intended to specify ENO’s exact revenue
requirements or exact rates that would allow ENO to collect such revenue amounts; and
WHEREAS, this resolution directs ENO to make numerous adjustments to its proposed
revenue requirements and rates; and
WHEREAS, it is not practical for the Council to calculate with precision the rates ENO
should be allowed to implement to comply with each aspect of this resolution; and

855

Ex. No. ENO-13 at 14:4-8.
Ex. No. ENO-13 at 14:10-12.
857
Ex. No. ENO-55 at 44.
858
Ex. No. ENO-21 at 2:10-11.
22

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 WHEREAS, the Council desires for its Advisors to confer with ENO as soon as practicable
to share with ENO the Advisors’ opinion as to the revenue requirement and rate class impacts of
this resolution; and
WHEREAS, in a motion in the instant proceeding filed before the Hearing Officer on July
11, 2019, ENO stated that it maintained its commitment that the effective date of the rates approved
by the Council will be the first billing cycle of August; and
WHEREAS, in the same motion in the instant proceeding filed before the Hearing Officer
on July 11, 2019, ENO discussed that a Council determination in the instant proceeding by
September would allow ENO to implement rates with the first billing cycle of November; and
WHEREAS, the Council desires for ENO to demonstrate how it will comply with each
provision of this resolution by making a compliance filing within 30 calendar days of the adoption
of this resolution providing all relevant documents for each of electric and gas, including,
1. Total company retail revenue requirements subtotaled by rate class (for electric,
each of the nine customer classes identified in the Revised Application).
a. A detailed set of work papers demonstrating that such revenue requirements
are in full compliance with each provision of this resolution and do reflect
costs not approved by the Council.
2. A computation of each fee, charge, rate, proscribed credit, or other mechanism by
which ENO receives revenue or credits against revenue requirement, that, when
applied to ENO’s Period II billing determinants, would allow ENO to collect its
revenue requirement for each rate class.
3. A computation of all credits and charges appropriate and required for ENO’s new
rates to be effective as of the first billing cycle of August 2019.

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 4. Interim rate adjustment riders for each of electric and gas to provide required credits
by rate class consistent with the excess revenues collected from each rate class from
the first billing cycle of August 2019 through the last billing cycle before new rates
go into effect.
a. The allocation of credits among the rate classes shall, to the extent
practicable, reflect the allocation method employed to collect excess
revenues (e.g., volumetric, demand, base rate).
b. The calculation of credits shall reflect carrying charges reflective of the
source of excess collections (e.g., excess collections through the FAC shall
accrue carrying charge credits at the FAC’s over/under rate). For excess
collections received from sources not having an over/under provision (e.g.,
base rates), the FAC’s over/under rate shall apply.
c. For any rider having a true-up mechanism and which under-collected its
approved revenue requirement through July 31, 2019, a provision to first
apply over collections from August 1, 2109 to the under-collection balance.
d. For electric, and to the extent reasonably practicable, a mechanism to return
over collections according to service area (i.e., the east and west bank of the
Mississippi River).
e. The interim rate adjustment rider may itself have a true-up provision.
f. The interim rate adjustment rider may return over collections over a
reasonable period of time not to exceed three months.

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 5. Copies of all documents, such as service schedules, riders (including the E-FRP
and GFRP riders), or terms affecting ENO’s service and rates that are required to
be altered to comply with this resolution, with rates presented therein.
6. For each ratemaking treatment ordered herein that is not consistent with ENO’s
Revised Application, a description of how ENO has implemented such treatment
and in which workpaper or other document its implementation may be
mathematically reviewed; and
WHEREAS, the Council does not seek to permit ENO to include adjustments as part of
its compliance filing that are not ordered herein that ENO may regard as ancillary consequences
of this resolution’s ratemaking directives or treatments; and
WHEREAS, the Council desires for ENO and the Advisors to work together to ensure
ENO’s compliance filing reflects every aspect the orders in this resolution; and
WHEREAS, the Council desires for the Advisors to review ENO’s compliance filing and
to have all relevant information required for such a review made available by ENO; and
WHEREAS, the Council desires for the Advisors to have fifteen (15) business days to
review ENO’s compliance filing for accuracy, compliance with this resolution, and consistency
with established Council ratemaking practices; and
WHEREAS, should the Advisors identify any error or deficiency in ENO’s compliance
filing, or require additional information to validate any part of ENO’s compliance filing, the
Council desires for the Advisors to identify and report to ENO such error or deficiency along with
any documentation and proposed correction, and then for ENO and the Advisors to work together
to resolve all issues; and

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 WHEREAS, the Council desires for the Advisors to, at the conclusion of their review of
ENO’s compliance filing, to state whether ENO’s compliance filing complies fully with this
resolution and is appropriate in all material aspects or to identify any remaining deficiencies; and
WHEREAS, the Council desires that, unless the Advisors conclude that ENO’s
compliance filing results in rates that are wholly inappropriate, that retail rates in compliance with
this resolution be affected, as soon as practicable by ENO notwithstanding any unresolved issues;
and
WHEREAS, the Council desires that, in the event there are disputes regarding ENO’s
compliance filing that cannot be resolved through good faith efforts by ENO and the Advisors, the
Advisors should report such issues, along with documentation and the Advisors’ recommended
correction, to the Council for the Council’s evaluation; and
WHEREAS, the Council desires that any corrections to ENO’s compliance filing that are
resolved after new rates are affected be made effective as of the first billing cycle of August
through the interim rate adjustment rider’s true-up mechanism;
WHEREAS¸ the Council has reviewed ENO’s Application and the record and considered
all arguments raised therein, to the extent that any specific argument is not herein addressed, the
Council has reviewed such argument and found that it was duplicative, cumulative, or otherwise
did not have sufficient impact on the Council’s decision to warrant discussion herein; and
NOW THEREFORE:
BE IT RESOLVED BY THE COUNCIL OF THE CITY OF NEW ORLEANS
THAT:
1.

ENO’s ROE shall be set at 9.35% and shall operate as a bandwidth midpoint for
purposes of the formula rate plan approved in this proceeding.

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 2.

ENO’s WACC shall be based on an equity ratio equal to the lesser of ENO’s actual
equity ratio or 50% and shall be used for all rate ratemaking purposes.

3.

ENO’s proposed depreciation rates are approved, except:
a.

ENO shall employ a 40-year depreciable life schedule for Union PB1
effective August 1, 2019.

b.

ENO shall employ a 50-year depreciable life schedule for NOPS.

c.

ENO shall amortize the general plant reserve deficiency over a 20-year
period.

4.

ENO’s proposal to exclude FIN 48 ADIT liability balances from its rate bases is
denied.

5.

ENO’s proposal to include NOLCF ADIT asset balances in its rate bases is denied.

6.

ENO shall employ its then current WACC with each calculation of Rider SSCO’s
rate.

7.

ENO is directed to create regulatory liabilities in the amount of $6,227,006 and
$823,146 for electric and gas respectively and include those liabilities related to
Stranded Plant ADIT in ENO’s regulatory rate base.

8.

ENO’s proposal to recover Restrictive Stock Incentive Plan costs is denied.

9.

ENO’s proposed pension asset adjustment is approved.

10.

ENO’s proposed GIRP rider is denied.
ENO’s GIRP infrastructure costs incurred as proformed through the end of 2019
and generally approved by Resolution R-17-38 are approved for cost recovery
through base rates.
Within 120 days from the date of this order, ENO is directed to propose, for Council
consideration, a rate of gas distribution pipe installation and dollar investment that
is required to maintain the safe operation of ENO’s gas system including potential
measures to mitigate the identified impact on ratepayers.
Within 120 days from the date of this order, ENO is directed to convene a a working
group composed of the Advisors, ENO, and Intervenors to explore appropriate cost
mitigation measures.
ENO’s recovery of utility conflict survey costs is approved and ENO is directed to
recover its related costs through base rates.

11.

ENO’s proposal to allocate certain PPA costs on a volumetric basis is denied.
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 12.

The Council denies CCPUG’s recommendations to:
a. Remove Capital Storm Restoration Costs from Plant
b. Remove Depreciation Expense Associated With Capital Storm Restoration
Costs
c. Remove Amortization of Algiers Migration Costs
d. Reduce Depreciation Expense – Correct Paterson Solar Depreciation Rate
e. Remove Reduction to ADIT for Excess ADIT Amortization in 2019
f. Remove Algiers Migration Costs Net of ADIT
g. Reduce Depreciation Expense – Use 0% Net Salvage for Union Power
Block #1
h. Extend Amortization of Algiers Transaction and Migration Costs to 10
Years
i. Remove Plant, A/D, and ADIT Proforma Adjustments Related to 2019
Additions
j. Remove Depreciation Expense Related to 2019 Plant Additions.

13.

The Council approves CCPUG’s recommendations to,
a. Correct Cash Working Capital to Include Dividend Component of Return
on Equity
b. Reduce Depreciation Expense – Use 40 Year Service Life for Union Power
Block #1
c. Extend Amortization Period for General Plant Reserve Deficiency from 10
Years to 20 Years
d. Remove Forecast 2019 Increases in Payroll and Related Expenses

14.

ENO’s proposal to eliminate and consolidate customer classes, including the
existing Algiers electric tariffs, to be combined into nine electric customer rate
classes is approved.

15.

ENO is directed to provide a complete cost of service analysis in support of the NJ
customers’ rates as part of future Council rate actions. ENO is further directed not
to execute any new NJ contracts without express Council approval.

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 16.

ENO’s DGM Rider is rejected and ENO is directed to recover its costs related to
grid modernization through base rates.

17.

18.

The AART Plan shall be adjusted consistent with the Advisors recommendations
except that instead of the mitigation plan being funded by the Legacy ENO
residential customers, it shall be funded by the Large Electric, Large Electric
High Load Factor, High Voltage, and Large Interruptible rate classes in
proportion to their base rate revenue requirements.
ENO’s proposed FAC Rider is approved as corrected by the Advisors.

19.

ENO’s proposed PGA Rider is approved as corrected by the Advisors.

20.

ENO shall revise its proposed PPCACR Rider in accordance with the
recommendations made by the Advisors for a PPCR Rider.

21.

The MISO Cost Recovery Rider is approved as proposed.

22.

The Company’s $8.07 electric residential customer charge shall remain
unchanged.

23.

ENO’s proposed AMI Riders and customer charges are denied.

24.

The Council approves ENO’s proposed electric and gas FRP mechanisms with the
following modifications:
a. Total utility cost of service, including total ENO revenues and expenses
shall be utilized in the FRP evaluation;
b. The Advisors’ proposed provision that “ENO may propose other known and
measurable costs that are supportable and expected to be incurred in the
prospective 12 months following the FRP evaluation Period” shall be add
to FRP Attachment C, Evaluation Period Adjustments, paragraph 8.
c. ENO’s proposed RIM is rejected.
d. The electric FRP decoupling revenue adjustment for each customer class
should be determined by comparing the evaluation period fixed and variable
revenue by class with the FRP evaluation period allocation of total ENO
fixed and variable revenue requirement.
e. No NOPS costs shall be included in the FRP mechanism until such time as
the construction of NOPS and associated costs have been approved through
a final judgment of the Council. To the extent that the Council’s judgment
becomes final, the proforma adjustments related to NOPS shall be included
in the FRP for the 12-month period subsequent to the FRP evaluation
period, which would encompass calendar year 2020 for the first FRP. If the
NOPS updated revenue requirement is included as a prospective proforma
adjustment in the bandwidth evaluation of the proposed E-FRP filed in
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 April 2020, the NOPS in-service rate adjustment, beginning with the month
following COD, would be effective until NOPS cost recovery is included in
the E-FRP revenue adjustment of the first FRP. If the NOPS updated
revenue requirement filing is not included as a prospective proforma
adjustment in the proposed E-FRP filed in April 2020, the NOPS in-service
rate adjustment, beginning with the month following COD, would be
effective until NOPS costs are included in the RPE bandwidth evaluation of
the following E-FRP. The E-FRP provision should include an allocation of
NOPS costs based on the rate case production demand allocation factor,
rather than total base rate costs.
25.

ENO’s decoupling proposal shall be modified such that a full decoupling
mechanism shall be filed with each electric E-FRP evaluation, with total allocated
costs of service for each customer class included in the decoupling revenue
adjustment, and the customer rate class allocation factors be updated annually with
current billing determinants. The decoupling adjustment shall be applied to all
customer classes if the E-FRP revenue adjustment is outside the bandwidth.
However, ENO shall, for rate classes Master Metered Non-Residential, Large
Electric High Voltage and Large Interruptible Service, implement a decoupling
revenue adjustment cap of 10% which will apply to each of the 3 annual E-FRP
evaluation period revenue adjustments provided that the total electric utility FRP
revenue adjustment for that evaluation does not exceed 10%. A new baseline of
customer class fixed and variable revenue requirements shall be determined in each
E-FRP from an allocation of costs and a return component based on the rates of
return corresponding to the customer class total revenues set in the instant docket.
Any adjustments that may be needed to the relative rates of return will be such that
those adjustments move the relative customer class rates of return toward the
utility’s rate of return based on the weighted average cost of capital. The revenue
deficiencies/excesses shall be determined for each customer class by comparing the
E-FRP customer class total revenue requirements with the customer class
evaluation period total actual revenues, with the decoupling adjustments applied
within each customer class using updated billing determinants excluding the
customer charge. The decoupling adjustment shall apply to proforma revenue
requirements and billing determinants in the E-FRP rate effective period, based
upon updated allocation factors and billing determinants in each E-FRP.

26.

ENO’s Green Pricing Proposal is be approved with the following modifications:
a. to the extent that the Council establishes a definition of “renewable
resources” in Council Docket No. UD-19-01, RECs used for the Green
Power Option must originate from sources meeting that definition;
b. to the extent the Council adopts a requirement in Council Docket No. UD19-01 that RECs be certified and/or tracked through a particular
program(s), such as Green-e, then RECs used for the Green Power Option
must be certified and/or tracked in the same manner, however, if the
Council does not establish such a requirement in UD-19-01, then RECs
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 shall be certified through Green-e (or such other certification as the Council
may approve in the future);
c. ENO’s pricing proposal is approved with the modification that in the
instance where there are not enough customers participating in the Green
Power Option that those customers could reasonably be expected to bear
the full costs of the program under the approved pricing structure, ENO
should be allowed to recover remaining costs from non-participating
ratepayers after submitting such costs to the Council for review and
demonstrating to the Council’s satisfaction that the costs were prudently
incurred, along with a request for Council authorization to either alter the
program to ensure that there is reasonable assurance that costs of the
program will be paid by participating customers going forward, or a request
to terminate the program; and
d. to the extent that there is not a final Council decision in Docket No. UD19-01 prior to the implementation of the Green Power Option, ENO shall
be allowed to utilize any Green-e certified RECs until such time as the
Council renders a decision in UD-19-01, at which point, ENO must
conform its use of RECs to the Council’s definition of renewable resources
and certification and/or tracking requirements on a going-forward basis.
27.

Both ENO’s and BSI’s Community Solar proposals are rejected.

28.

The Interim EECR Rider is approved.

29.

The proposed Rider DSMCR is rejected. In its place an EECR Rider consistent
with the Advisors’ proposal is approved. LCFC shall be addressed through the
decoupling process and shall not be included in the EECR Rider.

30.

ENO’s proposal to extend its MVLMR and MCDRR to its full service territory is
approved. ENO is directed to add customer support to the program, including the
provision of cost estimates to interested customers to encourage understanding of
and participation in the program.

31.

BSI’s CLEP proposal is rejected, as is BSI’s request that the Council form a
working group to implement CLEP.

32.

ENO’s proposed Rider EVCI is approved.

33.

ENO is authorized to invest of up to $500,000 in public EV charging
infrastructure that would provide free EV charging services at roughly 30-50
locations and shall consider stakeholder input as to the siting of such locations in
Council Docket No. UD-18-01.

34.

ENO is authorized to continue with the eTech program of rebates for the
installation of EV chargers, with the program to be included in the Energy Smart
Implementation Plan for PY 10-12. In the proceeding considering that
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 Implementation Plan, the parties should develop a method of assessing the
success of the eTech program separate and apart from the kWh and any kW
savings goals established in the Implementation Plan for PY10-12 such that
increased usage related to the success of the eTech plan does not negatively
impact ENO’s ability to achieve the savings goals related to other measures.
35.

The proposed changes to the Service Regulations, except for the proposed change
to Section 11 Continuity of Service, are approved. The proposed change to
Section 11 Continuity of Service is rejected.

36.

ENO shall correct tax errors in its Revised application related to FERC Accounts
410 and 190.

37.

ENO shall create a regulatory liability and enter such liability’s balance in its rate
base to reflect the economic benefit of cost free capital related to retired meters.

38.

ENO’s proposed $1/yr. per gas meter research and development charge is denied.

39.

ENO shall make a compliance filing with the Council within 30 calendar days of
the adoption of this resolution providing all relevant documents for each of electric
and gas, including,
a.

Total company retail revenue requirements subtotaled by rate class based
on Period II (for electric, each of the nine customer classes identified in the
Revised Application).
i. A detailed set of work papers demonstrating that such revenue requirements
are in full compliance with each provision of this resolution and do reflect
costs not approved by the Council.

b.

A computation of each fee, charge, rate, proscribed credit, or other
mechanism by which ENO receives revenue or credits against revenue
requirement, that, when applied to ENO’s Period II billing determinants,
would allow ENO to collect its revenue requirement for each rate class.

c.

A computation of all credits and charges appropriate and required for
ENO’s new rates to be effective as of the first billing cycle of August 2019.

d.

Interim rate adjustment riders for each of electric and gas to provide
required credits by rate class consistent with the excess revenues collected
from each rate class from the first billing cycle of August 2019 through the
last billing cycle before new rates go into effect.

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 e.

i.

The allocation of credits among the rate classes shall, to the extent
practicable, reflect the allocation method employed to collect excess
revenues (e.g., volumetric, demand, base rate).

ii.

The calculation of credits shall reflect carrying charges reflective of
the source of excess collections (e.g., excess collections through the
FAC shall accrue carrying charge credits at the FAC’s over/under
rate). For excess collections received from sources not having an
over/under provision (e.g., base rates), the FAC’s over/under rate
shall apply.

iii.

For any rider having a true-up mechanism and which undercollected its approved revenue requirement through July 31, 2019, a
provision to first apply over collections from August 1, 2109 to the
under-collection balance.

iv.

For electric, and to the extent reasonably practicable, a mechanism
to return over collections according to service area (i.e., the east and
west bank of the Mississippi River).

v.

The interim rate adjustment rider may itself have a true-up
provision.

vi.

The interim rate adjustment rider may return over collections over a
reasonable period of time not to exceed three months.
Copies of all documents, such as service schedules, riders (including the EFRP and GFRP riders), or terms affecting ENO’s service and rates that are
required to be altered to comply with this resolution, with rates presented
therein.

40.

For each ratemaking treatment ordered herein that is not consistent with ENO’s
Revised Application, a description of how ENO has implemented such treatment
and in which workpaper or other document its implementation may be
mathematically reviewed.

41.

To the extent not otherwise modified in this Resolution, ENO’s remaining
proposals are approved as filed by ENO.

42.

The Council’s Utility Advisors are directed to work with the City and ENO to
resolve the City’s outstanding billing issues.

THE FOREGOING RESOLUTION WAS READ IN FULL, THE ROLL WAS
CALLED
ON THE ADOPTION THEREOF AND RESULTED AS FOLLOWS:

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 YEAS:

NAYS:

ABSENT:

AND THE RESOLUTION WAS ADOPTED.

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