RESOLUTION
R-18-65
CITY HALL: March 8, 2018
BY:

COUNCILMEMBERS WILLIAMS, HEAD, GUIDRY, BROSSETT AND GRAY

APPLICATION OF ENTERGY NEW ORLEANS, INC. FOR APPROVAL TO
CONSTRUCT NEW ORLEANS POWER STATION AND REQUEST FOR COST
RECOVERY AND TIMELY RELIEF
RESOLUTION AND ORDER REGARDING THE APPLICATION OF ENTERGY NEW
ORLEANS, INC. FOR APPROVAL TO CONSTRUCT NEW ORLEANS POWER
STATION AND REQUEST FOR COST RECOVERY AND TIMELY RELIEF
DOCKET NO. UD-16-02
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 1 (“ENO” or “Company”), effective September
1, 2015, is a public utility providing electric and natural gas service to all of New Orleans; and
WHEREAS, ENO is a wholly-owned subsidiary of Entergy Utility Holding Company,
LLC.

1

The other four operating companies are Entergy Arkansas, Inc. (“EAI”), Entergy

Pursuant to a Council-approved restructuring, that was effective December 1, 2017, Entergy New Orleans, Inc. is
now operating as Entergy New Orleans, LLC.

 Louisiana, LLC (“ELL”), Entergy Mississippi, Inc. (“EMI”), and Entergy Texas, Inc. (“ETI”).
These five operating companies are referred to collectively as the “Operating Companies;” and
Background
WHEREAS, the Council recognizes that a request to authorize ENO to build a new
central station generator located within the City of New Orleans is a significant undertaking of
considerable interest to ratepayers and the New Orleans community; and
WHEREAS, the Council has been considering the ongoing needs of electric customers
in New Orleans in light of the 2016 deactivation of the two natural gas-fired units at the Michoud
site for nearly three years; and
WHEREAS, for more than 50 years, the Michoud generating station in New Orleans
East served as the cornerstone of ENO’s operating system. ENO’s transmission system was
largely designed and evolved around the Michoud plant. 2 In June of 2016, ENO deactivated
Michoud based on consideration of maintenance and operational issues. 3 This resulted in the
loss to ENO of approximately 781 MW of local generating capacity, 4 an left New Orleans with
no local generating resource within the City; and
WHEREAS, since at least the 1990s until its deactivation, the Michoud generating
station was committed to operation during high load periods due to local area voltage and
reliability problems, and in the event of transmission constraints and electrical system
contingencies in both Entergy’s Amite South and the Downstream of Gypsy (“DSG”) area. For
example, in 2008 when Hurricane Gustav struck the region, Michoud provided essential service

2

In re. Supplemental and Amending Application of Entergy New Orleans, Inc., Hearing Transcript, Docket No. UD16-02 (Dec. 18, 2017), 336:4-9 (“Hr’g Tr. 12/18/17”).
3
Direct Testimony and Exhibits of Charles Rice, Jr., Docket No. UD-16-02, at 3:7-8 (June 20, 2016) (“Rice-1”).
4
Rice-1 at 3:8.

2

 to New Orleans when other portions of Entergy’s system were down. 5 When ENO began
considering the retirement of the last Michoud unit in early 2015, the Council was deeply
concerned about ENO’s ability to continue to provide reliable service at a reasonable cost with
no generation in the City, and particularly with no resource in the eastern region of ENO; and
WHEREAS, during that same time period when ENO was considering deactivation of
Michoud, the Council’s Utility Advisors (“Advisors”) were working with ENO both on
negotiating the termination of the Entergy System Agreement 6 and on ENO’s Integrated
Resource Planning (“IRP”) process. In both of these processes, the Council, the Advisors and
ENO discussed ENO’s generation deficit and potential solutions to mitigate the risks associated
with a total lack of a local resource in New Orleans; and System Agreement Settlement
WHEREAS, for over 50 years, the Entergy Operating Companies operated as a single
integrated and coordinated system with their relationships governed by a contract known as the
Entergy System Agreement; and
WHEREAS, the Entergy System Agreement provided for sharing and joint planning of
transmission and generation and associated costs, which created significant economies of scale
for the Operating Companies, and from which ENO, as the smallest of the Operating Companies
with the fewest resources of its own, particularly benefitted; and
WHEREAS, the termination of the Entergy System Agreement was, therefore,
potentially detrimental to ENO’s customers, particularly with the clock already winding down on
the remaining life of the existing Michoud units; and

5

Direct Testimony and Exhibits of Charles Long, Docket No. UD-16-02, at 13:17-14:3 (June 20, 2016) (“C. Long1”); Rebuttal Testimony and Exhibits of Charles Long, Docket No. UD-16-02, at 28:1-29:3 (Nov. 30, 2017) (“C.
Long-3”).
6
See Resolution No. R-15-524 (Nov. 5, 2015) (related to Council Docket Nos. UD-13-03 and UD-13-04).

3

 WHEREAS, when negotiations to terminate the Entergy System Agreement began under
the auspices of the Federal Energy Regulatory Commission (“FERC”), it was vital to the Council
that ENO continue to have access to capacity and energy at a reasonable cost; and
WHEREAS, a filing by Entergy Services, Inc. (“ESI”) at FERC triggered an intervention
period which allowed any interested parties to intervene in FERC’s public proceeding regarding
the proposal to terminate the System Agreement. Once that intervention period had elapsed,
FERC set the proceeding for settlement discussions facilitated by a FERC Administrative Law
Judge (“ALJ”); 7 and
WHEREAS, the Advisors, on behalf of the Council, negotiated with ENO and the other
parties to the FERC case in formal settlement proceedings before an ALJ, and a settlement
between all parties to the case was ultimately reached. On August 14, 2015, ESI filed the
settlement in the public proceeding at FERC. 8 The Settlement Agreement was subject to the
review and approval of the Council as well as of the other regulatory commissions party to the
Settlement Agreement; and
WHEREAS, the Settlement Agreement resolved a host of issues. Among these, the
Settlement Agreement provided that ENO would explore the possibility of developing peaking
generation in New Orleans. It did not mandate, pre-select or pre-approve any particular resource
or any particular site. Specifically, the Settlement Agreement provided:
ENO will use reasonable diligent efforts to pursue the development
of at least 120 MW of new-build peaking generation capacity
within the City of New Orleans. As part of this commitment, ENO
will fully evaluate Michoud or Paterson, along with any other
7
Entergy Services, Inc., Combined Notice of Filing #2, Docket Nos. ER14-75-000, et al. (Oct. 15, 2013). Entergy
Services, Inc., Order Conditionally Accepting Notices of Cancellation and Accepting and Suspending Proposed
Amendment, Establishing Hearing and Settlement Judge Procedures, and Consolidating Proceedings, 149 FERC
¶°61,262 (2014).
8
Settlement Agreement of Entergy Services, Docket Nos. ER14-75, et al. (Aug. 14, 2015) (“Settlement
Agreement”).

4

 appropriate sites in the City of New Orleans, as the potential site
for a combustion turbine (“CT”) or other peaking unit to be owned
by ENO, or by a third party with an agreed-to PPA to ENO. This
evaluation will take into consideration, among other material
considerations, the results of the Michoud site analysis that was
completed in connection with the Summer 2014 Request for
Proposal; and
ENO commits to use diligent efforts to have at least one future
generation facility located in the City of New Orleans; …. 9
WHEREAS, further, the Settlement Agreement did not assure that any resource would
be approved for construction in the City.

It reflected the Council’s concern about the

deactivation of Michoud, which ENO had long depended on to support reliability in the City, at
the same time that the resource sharing contract that had benefitted New Orleans for decades was
terminating. 10 In light of this, the Settlement Agreement established ENO’s commitment to
examine the potential of a local resource; and
WHEREAS, to the extent that ENO identified an appropriate resource and location, any
approval would be subject to the full public interest determination that the Council undertakes in
evaluating requests by ENO to add generation to its portfolio of resources serving New Orleans.
This was spelled out in the Settlement Agreement, which was filed at FERC subject to formal
approval by the Council and the other retail regulators party to the case:
The commitments set forth in this [section] are subject to mutually
satisfactory resolution of all material considerations, including,
without limitation: (a) financial feasibility for ENO;
(b) affordability for ENO customers; (c) economic feasibility in
comparison to other potential projects, locations, or alternatives;
(d) timely rate recovery; (e) regulatory jurisdiction over such
facility(ies) to the extent not owned by ENO; and (f) consistency
with sound utility practice and planning principles. 11

9

Id. at 13-14.
Hr’g Tr. 12/18/17, 247:18-248:11.
11
Settlement Agreement at 14.
10

5

 WHEREAS, before approving the Settlement Agreement, the Council provided all
parties affected by it an opportunity to understand the proposal, submit comments and have their
views considered. 12 The Council established a procedural schedule that allowed the parties to its
proceedings addressing the System Agreement termination (Docket Nos. UD-13-03 and UD-1304) as well as members of the public, to submit comments and reply comments regarding the
proposed Settlement Agreement, which the Council considered in deciding whether to approve
the Settlement Agreement.

Consistent with the Council’s practice generally, the process

included the publication of notice of the proceedings; and
WHEREAS, public meetings were held by the Utility, Cable, Telecommunications, and
Technology Committee (“UCTTC”) and the full Council on September 30 and November 5,
2015, respectively, where the Settlement Agreement was considered. No party or member of the
public opposed the Settlement Agreement.

On November 5, 2015, the Council adopted

Resolution No. R-15-524 which found the FERC Settlement Agreement, including ENO’s
commitment to use reasonable diligent efforts to pursue development of a peaking resource in
the City, to be just and reasonable and in the public interest. 13

The resolution was made

available to the public and was discussed at a UCTTC meeting, which was recorded on video,
broadcast and made available over the Council’s website; 14 and ENO’s IRP Process
WHEREAS, through the Council’s IRP proceedings, ENO identifies its long-term
resource needs and conducts an economic analysis of what type of resource is likely to be the
most economically beneficial in meeting an identified resource need. The IRP does not dictate

12

Resolution No. R-15-437 at 4 (Sept. 3, 2015).
Resolution No. R-15-524 at 12.
14
Videos of Council meetings are available in the Council’s online archives,
http://www.nolacitycouncil.com/video/video_legislative.asp.
13

6

 the implementation of specific projects; rather, it identifies the need and gives the utility a
general direction to explore in meeting that need; and
WHEREAS, in the course of preparing its 2015 Final IRP in Council Docket No. UD08-02, ENO engaged in extensive modeling and considered a wide range of future scenarios and
resource alternatives. That process identified the Company’s substantial need for peaking and
reserve capacity; 15 and
WHEREAS, ENO’s IRP process provided multiple opportunities for meaningful public
participation. 16 The Council has established a collaborative approach to long-term resource
planning that provides interested parties access to substantial advance information about ENO’s
plans to meet its customers’ power needs. 17 The IRP process was open to the public to intervene
and participate formally as a party to the proceeding, or simply to attend multiple technical
conferences to hear about the IRP and present two minutes of verbal comments to the Council in
a public hearing regarding the 2015 Final IRP; 18 and
WHEREAS, in the 2015 Final IRP process, the Council set forth four milestones and
required that at each one, ENO (1) provide a report from ENO to the Intervenors, Advisors,
public, and the Council; (2) hold a technical conference, (3) set up a question and answer period
where all parties and members of the public may ask questions over ENO’s website with answers
publicly posted; (4) allow Intervenors to file comments on ENO’s report, and (5) obtain feedback
and input from the Council; 19 and

15

In Re: Resolution Regarding the Proposed Rulemaking to Establish Integrated Resource Planning Components and
Reporting Requirements for Entergy New Orleans, Inc., 2015 Integrated Resource Plan, Docket No. UD-08-02, at
75 (Feb. 1, 2016) (“2015 Final IRP”); Rebuttal Testimony and Exhibits of Charles Rice, Jr., Docket No. UD-16-02,
at 8:4-9 (Nov. 30, 2017) (“Rice-4”)
16
Resolution No. R-14-224 at 16 (June 5, 2014).
17
Resolution No. R-14-224; Rebuttal Testimony and Exhibits of Seth Cureington, Docket No. UD-16-02, at 79:1317 (Nov. 30, 2017) (“Cureington-7”).
18
Resolution No. R-17-100 at 5-8 (Feb. 23, 2017).
19
See Resolution No. R-14-224 at 16. See also, discussion in Cureington-7 at 81 nn.111-114.

7

 WHEREAS, the Council subsequently took further steps to allow for participation by
additional intervenors. 20 With Resolution No. R-14-364, many other parties were allowed to
intervene in the 2015 Final IRP proceeding.

Among the parties who intervened in that

proceeding were Air Products and Chemicals, Inc. (“Air Products”), the Alliance for Affordable
Energy (“Alliance”), the Sierra Club Environmental Law Program (“Sierra Club”) and Posigen
of Louisiana, LLC (“Posigen”), and at least nine other entities and organizations; 21 and
WHEREAS, ENO issued 30 days’ notice of each technical conference and made
materials available to the public. These meetings were held in central locations in the City,
including a public technical conference in New Orleans East regarding the 2015 Final IRP in
May of 2016. 22

ENO held more technical conferences than the minimum required by the

Council. 23 In response to feedback it received on the draft IRP plan, ENO took steps to increase
transparency of the process and to incorporate stakeholder input. 24 ENO created a Stakeholder
Input Case to supplement the 2015 Final IRP. 25 The Council also directed ENO to hold a
technical conference and provide the opportunity for public review and comment on the 2015
Final IRP, 26 and a public hearing was held; 27 and
WHEREAS, the preferred portfolio selected by ENO in its 2015 Final IRP process
included a 250 MW combustion turbine (“CT”) unit, but the IRP was not a formal proposal to
construct the New Orleans Power Station (“NOPS”). 28 By the time the Council’s final order
regarding the 2015 Final IRP was issued, ENO’s Initial Application to construct NOPS had

20

See Resolution No. R-14-364 at 7-8 (Sept. 4, 2014). See also Cureington-7 at 81 n.110.
Cureington-7 at 81. See also, Resolution No. R-14-364 at 8, Resolution No. R-16-104 at 7 (Apr. 7, 2016).
22
Cureington-7 at 82:1-13 and nn.115-117.
23
Cureington-7 at 82:14-83:3.
24
Cureington-7 at 83:10-14.
25
Cureington-7 at 83:14-18.
26
Resolution No. R-16-104 at 6-8.
27
Resolution No. R-16-104 at 8.
28
Cureington-7 at 79:23.
21

8

 already been filed. The Council in its resolution accepting the IRP was extremely clear that its
acceptance of the IRP did not, in any way, constitute approval of ENO’s NOPS application:
1.
All issues related to ENO’s NOPS CT proposal should be
fully vetted in Council Docket No. UD-16-02 including, but not
limited to the need for a CT, size, timing, environmental concerns,
social justice, cost, transmission, and reliability considerations.
ACCEPTANCE OF THIS IRP SHALL HAVE NO
PRECEDENTIAL EFFECT WITH RESPECT TO THE
COUNCIL’S EVALUATION OF ENO’S NOPS CT
APPLICATION IN COUNCIL DOCKET UD-16-02. 29
WHEREAS, in light of the analysis performed in the 2015 Final IRP proceeding, ENO
filed an application before the Council for the proposed NOPS that for the first time proposed a
specific technology and location for the CT plan contemplated in the 2015 Final IRP analysis;
and
WHEREAS, in Council Resolution No. R-15-599, 30 the Council found that it would be
reasonable in the development of subsequent Energy Smart Program Years (Program Year 7 and
beyond), for the Company to incorporate in its Energy Smart and IRP filings for evaluation by
the Advisors, Intervenors, and the Council the goal of increasing the projected savings from the
Energy Smart program by 0.2% per year, until such time as the program generates kWh savings
at a rate equal to 2% of annual kWh sales (“2% DSM Goal”). The Council also reminded ENO,
in Resolution No. R-17-100 that it should include in its Energy Smart filings (Program Year 7
and beyond) and its future IRP filings, for evaluation by the Advisors, Intervenors, and the
Council an alternative goal of increasing the projected savings from the Energy Smart program
by 0.2% per year, until such time as the program generates kWh savings at a rate equal to 2% of
annual kWh sales; and

29
30

Resolution No. R-17-100.
Resolution No. R-15-599 (Dec. 10, 2015).

9

 WHEREAS, ENO has committed to the Council to add 100 MW of renewable resources
to its portfolio; 31 and
NOPS Application
WHEREAS, ENO filed its original proposal to construct NOPS in June 2016; 32 and
WHEREAS, the Initial Application outlined ENO’s proposal to construct a 226 MW CT
generation facility on the Michoud site in New Orleans East. In addition to seeking approval to
construct NOPS, ENO seeks approval of a contemporaneous exact cost recovery rider on
customer bills, effective beginning with commercial operation of the plant, to recover non-fuel
costs; and
WHEREAS, in its Initial Application ENO indicated it was contemplating a long-term
service agreement (“LTSA”) with the original equipment manufacturer for major maintenance.
If such an LTSA is executed, ENO seeks authorization to recover those costs through a fuel
adjustment clause (“FAC”) mechanism; and
WHEREAS, ENO also seeks approval of its proposed monitoring plan. In the Initial
Application, ENO sought approval by January 2017, with the expectation that the CT would be
in commercial operation by October 2019. ENO estimated that the cost of the project would be
$216 million. In addition to citing its reliability and capacity need, ENO stated that construction
of the project would have a positive impact on the New Orleans and Louisiana economies in
terms of new business sales, household earnings and jobs; and
WHEREAS, on November 18, 2016, at the direction of the Council, ENO filed its
“Supplemental Testimony of Entergy New Orleans, Inc. for Approval to Construct New Orleans

31

Rice-3 at 20:2-10, see also, Council Resolution No. R-17-428 at 2.
Application of Entergy New Orleans, Inc. for Approval to Construct New Orleans Power Station and Request for
Cost Recovery and Timely Relief, Docket No. UD-16-02 (June 20, 2016) (“Initial Application”).
32

10

 Power Station and Request for Cost Recovery and for Timely Relief.” This filing included
additional testimony and analysis requested by the Council upon the advice of the Advisors; and
WHEREAS, in January 2017, ENO received an updated forecast of projected customer
demand for the 20-year planning horizon. The updated load forecast indicated demand has
moderated by an average of 40 MWs per year compared to the forecast used in the Initial
Application. On February 14, 2017, after the Intervenors had filed their direct testimony but
before the Council’s Advisors filed direct testimony, ENO filed a motion to suspend the
procedural schedule to analyze the implications of the updated forecast on its proposed project.
ENO also sent an email to its customers explaining that the Company had requested to
temporarily suspend the procedural schedule in the docket so that it could evaluate the
implications of the updated load forecast. On April 2017, ENO sent an additional email updating
customers about ENO’s progress and its investigation into a smaller alternative resource; 33 and
WHEREAS, on July 6, 2017, ENO filed a “Supplemental and Amending Application of
Entergy New Orleans, Inc. for Approval to Construct New Orleans Power Station and Request
for Cost Recovery and Timely Relief.” 34 In this filing, ENO still advocated construction of the
226 MW CT Alternative, but also submitted an alternative proposal to construct a smaller 128
MW “Alternative Peaker” at the Michoud site. The alternative proposal entails construction of
seven Wärtsilä 18V50SG Reciprocating Internal Combustion Engine (“RICE”) Generator sets
(“RICE Alternative”); and
WHEREAS, ENO explains in its Supplemental Application, in addition to its smaller
size, which is more closely matched to ENO’s revised projected capacity need, the RICE
33
Entergy New Orleans, Inc.’s Motion to Suspend the Current Procedural Schedule Temporarily and to Set Date for
Follow-Up Status Conference, Docket No. UD-16-02 (Feb. 14, 2017).
34
Supplemental and Amending Application of Entergy New Orleans, Inc. for Approval to Construct New Orleans
Power Station and Request for Cost Recovery and Timely Relief, Docket No. UD-16-02 (July 6, 2017)
(“Supplemental Application”).

11

 Alternative has several benefits not offered by the CT. It has on-site black-start capability, lower
emissions, uses far less groundwater in its cooling process, and permits greater operational
flexibility. 35 The anticipated cost of the RICE Alternative is $210 million, and, if approval had
been granted by October 2017, the unit would have been in commercial operation by
approximately October 2019; 36 and
WHEREAS, in the Supplemental Application, ENO also advised the Council that the
expected cost of the CT had increased by $16 million due to delays. If the Council had approved
the CT by the end of October 2017, it would have been operational by approximately November
2020; and
WHEREAS, when ENO filed its Supplemental Application, the Council adopted
Resolution No. R-17-426, 37 which established a modified procedural schedule to examine the
revised proposal. This resolution required ENO to conduct no less than five well-advertised
public outreach meetings (one in each Council district) and for its Council Utilities Regulatory
Office to conduct one public meeting on ENO’s Application in the Council chambers. In total,
ENO has held at least 21 public meetings regarding NOPS, including several meetings in New
Orleans East. 38 Notices for the meetings and handouts provided at the meetings were available
in English, Spanish and Vietnamese in order to further participation by affected communities; 39
and
WHEREAS, we note that throughout the application process, ENO participated in
multiple meetings with community groups, neighborhood associations, and other civic

35

Supplemental Application at 8.
Supplemental Application, citing Supplemental and Amending Direct Testimony and Exhibits of Charles Rice, Jr.,
Docket No. UD-16-02, at 12:4-6 (July 6, 2017 (“Rice-3”).
37
Resolution No. R-17-426 (Aug. 10, 2017).
38
Cureington-7 at 87:2-17, 90:1-16; Rice-4 at 17:10-20. Report Regarding Public Outreach Meetings, Docket No.
UD-16-02 were filed on Dec. 22, 2016, Aug. 17, 2017, Aug. 23, 2017, Sept. 12, 2017, and Oct. 4, 2017.
39
Cureington-7 at 90:8-10.
36

12

 organizations to discuss issues surrounding NOPS, including several meetings in New Orleans
East. 40 Council Resolution Nos. R-16-506 41 and R-17-426 provided interested parties and the
public at large substantial notice and opportunity to be heard concerning the Company’s NOPS
proposal, including public outreach meetings in each Council district and two public hearings in
Council Chambers; and
WHEREAS, in Resolution No. R-16-506 issued on November 3, 2016 setting the
procedural schedule for the consideration of ENO’s Initial Application for approval to construct
NOPS, the Council clearly articulated its intention to afford meaningful public involvement in
the decisional process:
[T]he Council intends to provide the residents of the City of New Orleans
with an open and transparent process that will allow for multiple
opportunities for the public to communicate its views to ENO and the
Council as they relate to the construction of the proposed project…. 42
Moreover, in that resolution, the Council also required ENO to make a
supplemental filing to address certain environmental concerns; created an opportunity for
Intervenors to file testimony; required at least two public outreach meetings; provided for
a public hearing; and established a mechanism for interested persons to receive email
notice of any public meetings or hearings concerning the NOPS application; and
WHEREAS, the following parties intervened in the docket examining the NOPS
proposal:
•
•
•
•
•

Alliance for Affordable Energy
PosiGen
Air Products
Deep South Center for Environmental Justice, Inc. (“DSEJ”)
New Orleans Cold Storage & Warehouse Co. Ltd. (NOCS”)

40

Cureington-7 at 87:11-13.
Resolution No. R-16-506 at 8 (Nov. 3, 2016).
42
Resolution No. R-16-506 at 8.
41

13

 •
•
•

Gulf States Renewable Energy Industries Association
Sierra Club
350 Louisiana - New Orleans; and

WHEREAS, in addition to the public meetings, parties and intervenors to this
proceeding were given the opportunity to file written testimony, conduct extensive discovery,
including depositions; and in December 2017, a five-day public evidentiary hearing was held
before a Hearing Officer to examine ENO’s NOPS application; and
WHEREAS, the Hearing Officer certified the Administrative Record to the Council on
January 22, 2018, 43 and the matter is now before the Council for its consideration; and
Issues Before the Council
WHEREAS, the Council reviews such applications to determine whether or not the
utility’s proposal is in the public interest. The public interest standard is designed to “assure the
furnishing of adequate service to all public utility patrons at the lowest reasonable rates
consistent with the interest both of the public and of the utilities.” 44 Determining whether a
proposal is in the public interest requires the Council to balance all relevant factors, no single
element of the public interest should be considered in isolation; and
WHEREAS, in Resolution No. R-17-426, the Council required the parties to submit a
Joint Statement of Issues after all testimony had been submitted to the Council setting forth the
issues that have been raised in the case for the Council’s consideration; and

43

Transmittal Letter to Council with Order Certifying Record from Judge Jeffrey S. Gulin, Docket No. UD-16-02
(Jan. 22, 2018).
44
City of Plaquemine v. Louisiana Pub. Serv. Comm’n, 282 So. 2d 440, 443 (La. 1973). In that case, the court
writes: “The entire regulatory scheme, including increases as well as decreases in rates, is indeed in the public
interest, designed to assure the furnishing of adequate service to all public utility patrons at the lowest reasonable
rates consistent with the interest both of the public and of the utilities. Thus the public interest necessity in utility
regulation is not offended, but rather served by reasonable and proper rate increases notwithstanding that an
immediate and incidental effect of any increase is improvement in the economic condition of the regulated utility
company.” Id. at 442-443.

14

 WHEREAS, the Council received over 2,700 pages of testimony and exhibits regarding
the NOPS applications; and
WHEREAS, after all testimony and exhibits were filed with the Council, on December 1,
2017, ENO, the Advisors, the Alliance, Sierra Club, DSCEJ, 350 Louisiana-New Orleans, and
Air Products together submitted a Joint Statement of Issues noting that there are no uncontested
issues in the case and setting forth the following contested issues for the Council’s consideration
as the Council deliberates on whether the NOPS proposals are in the public interest:
I.

II.

Whether ENO’s analysis of need is sufficient to justify an investment
A.

Whether ENO has demonstrated a capacity need

B.

Whether ENO has demonstrated a reliability need

Whether either of ENO’s choices of technology(ies) is in the public interest
A.

Whether ENO’s selection of a CT unit is in the public interest

B.

Whether ENO’s selection of a RICE unit is in the public interest

C.

Whether ENO appropriately considered a full range of options to meet the
identified need

III.

Whether ENO’s selection of the Michoud site is reasonable

IV.

Whether ENO’s proposed costs, cost recovery mechanism and Monitoring Plan
are just and reasonable and should be approved by the Council; 45 and

WHEREAS, post-hearing briefs addressing these issues were filed by ENO, Air
Products, NOCS, a coalition of the Alliance, DSCEJ, and 350-New Orleans, and Sierra Club
(“Joint Intervenors”), and the Advisors; and
WHEREAS, ENO urges the Council to approve its Supplemental Application and certify
construction of either the CT Alternative or the RICE Alternative and approve a cost recovery

45

In Re: Application of Entergy New Orleans, Inc. for Approval to Construct New Orleans Power Station and
Request for Cost Recovery and Timely Relief, Joint Statement of Issues, at 1-2 (Docket No. UD-16-02) (Dec. 1,
2017).

15

 mechanism that provides ENO a full and fair opportunity to recover prudently incurred costs on
a timely/in-service basis; 46 and
WHEREAS, ENO argues that (1) it has a long-term need for peaking capacity, which
NOPS will provide; (2) it has had a current and persisting reliability need since the deactivations
of Michoud Units 2 and 3; (3) in its long-term planning process, ENO considered a full range of
options to meet its capacity and reliability needs, and the proposed NOPS units are the
appropriate choices to meet those needs; (4) the Michoud site is the ideal location to construct
NOPS; and (5) the proposed costs of the NOPS units are reasonable and necessary to address
ENO’s capacity and reliability needs, and ENO’s proposed cost recovery mechanism and
monitoring plan are likewise reasonable and necessary to secure the benefits of local generation
for ENO’s customers; 47 and
WHEREAS, Air Products states that (1) ENO has demonstrated a need for capacity, both
from the perspective of achieving a reasonable reserve margin above its expected peak load, and
also from a locational reliability perspective; (2) the CT Alternative is too large and too
inflexible to meet the needs of ENO’s customers and that the RICE Alternative is in the public
interest; but that not all seven of the Wärtsilä units should be constructed at this time; (3) it is not
aware of any viable site for construction of NOPS other than the Michoud site, and supports
construction of the RICE facility at that location; and (4) as a means of cost recovery it supports
the Advisors’ proposed two-step rate increase that would be developed in conjunction with the
2018 Combined Rate Case filing, with the first step being to exclude the revenue requirement
associated with NOPS while the second step would recognize a higher level of rates that would

46

Post-Hearing Brief of Entergy New Orleans, LLC, Docket No. UD-16-02, at 156 (Jan. 19, 2018) (“ENO PostHearing Brief”).
47
ENO Post-Hearing Brief at 4-5.

16

 become effective following the commercial operation date (“COD”) of the NOPS unit. 48 Air
Products objects to the cost recovery rider, as proposed by ENO, but states that if such a rider is
the Council’s preferred approach, it supports the recommendation of the Advisors that if this
route is taken, the allocation to customer classes be as an equal percentage of base rate
revenues. 49 Air Products also argues that it is being overcharged by the existing Purchased
Power Capacity Acquisition Cost Recovery (“PPCACR”) Rider because that rider allocates the
non-fuel revenue requirements on a customer class kilowatt hour (“kWh”) basis, which is not
cost-based, Air Products requests that the Council order the realignment of PPCACR Rider
recoveries across customer classes as an equal percent of base rate revenues. 50 Air Products
requests that if this is not possible, that it be compensated for the overcharges in the 2018
Combined Rate Case. 51

Air Products also supports the position of the Advisors on the

monitoring plan; 52 and
WHEREAS, NOCS argues that (1) ENO fell far short of meeting its burden of proving a
capacity need for the 226 MW CT Alternative; (2) it is dubious whether ENO’s evidence of a 99
MW capacity shortfall surfacing in 10 years is sufficient to justify the 128 MW RICE Alternative;
(3) the evidence reveals a transmission-related reliability problem, not a generation-related
reliability problem; (4) the record does not contain an analysis of whether the St. Charles Power
Station could have provided sufficient reliability benefits to address ENO’s needs; (5) the
selection of the CT Alternative is not in the public interest, and even ENO’s own analyses of the
optimal mix of generating resource technologies to fill its purported need indicates that

48
Brief of Air Products and Chemicals, Inc., Docket No. UD-16-02, at 3-4 (Jan. 19, 2018) (“Air Products PostHearing Brief”).
49
Air Products Post-Hearing Brief at 4.
50
Air Products Post-Hearing Brief at 4.
51
Air Products Post-Hearing Brief at 4.
52
Air Products Post-Hearing Brief at 4.

17

 combined cycle gas turbine (“CCGT”) technology is the preferred resource solution; (6) the
selection of the RICE Alternative suffers from the same arbitrary, unsupported foundation as the
selection of the CT Alternative, thus, ENO has not shown that the RICE Alternative is in the
public interest; (7) ENO’s refusal to conduct a Request for Proposal (“RFP”) process to solicit
offers from third parties that could have been less expensive than the NOPS project, denied the
City Council the ability to compare the NOPS project to alternative resources or a mix of
resources that could serve the same supply role, on a total production cost basis, and undermines
ENO’s ability to prove either version of the NOPS project is the least cost option for the citizens
of New Orleans; (8) ENO neglected to consider the full range of options to meet any identified
need because it did not use an RFP; (9) the City Council should initiate a rulemaking to develop
RFP rules; and (10) ENO further neglected to consider the full range of options to meet any
identified need because it did not fully analyze a transmission solution; 53 and
WHEREAS, the Joint Intervenors argue that ENO has provided the Council with a series
of shifting and illusory claims about the need for a gas plant. 54 The Joint Intervenors argue that
the driving purpose behind the inconsistencies in ENO’s case is its desire to build, and add to its
rate base, a $200-plus million gas-fired facility and that its desire for a new gas plant has resulted
in its failure to seriously evaluate any alternative other than a gas plant to meet the City’s
capacity or reliability needs. 55

The Joint Intervenors take issue with ENO’s decision to

deactivate Michoud Units 2 and 3 and its failure to inform the Council in a timely fashion of the
reliability impacts of doing so. 56

They argue that a study conducted by the Midcontinent

53
Post-Hearing Brief of New Orleans Cold Storage & Warehouse Co. Ltd., Docket No. UD-16-02, at 1 (Jan. 19,
2018) (“NOCS Post-Hearing Brief”).
54
Post-Hearing Brief of Alliance for Affordable Energy, Deep South Center for Environmental Justice, Inc., 350New Orleans, and Sierra Club, Docket No. UD-16-02, at 3 (Jan. 19, 2018) (“Joint Intervenors’ Post-Hearing Brief”).
55
Joint Intervenors’ Post-Hearing Brief at 3-4.
56
Joint Intervenors’ Post-Hearing Brief at 4.

18

 Independent System Operator, Inc. (“MISO”) in 2014 proves that there are no reliability
concerns posed by the plan to retire Michoud Units 2 and 3. 57 The Joint Intervenors detail the
history of ENO’s retirement of the Michoud Units 2 and 3 and its proposal to build NOPS and
conclude that ENO has tried to convince the Council there is no option other than to build the
NOPS unit. 58 The Joint Intervenors argue that due to the declining load forecast, ENO cannot
justify a gas plant as big as the CT Alternative. 59 The Joint Intervenors argue that ENO changed
its argument, and is now relying upon a reliability need rather than a capacity need to justify a
gas plant, and that ENO has now added arguments that a gas plant would assist in storm recovery
and might be able to assist in backing up Sewerage & Water Board of New Orleans (“S&WB”),
though ENO has not done sufficient modeling to support either claim; 60 and
WHEREAS, the Joint Intervenors argue that regardless of their assertions that (1) the gas
plant costs more than the alternatives studied, (2) ENO never fully evaluated the transmissionupgrades solution, (3) it would create a very large and risky capacity surplus for the City, (4) the
gas plants would create significant health and flood risks for New Orleans East communities, and
(5) the units would contribute to air and climate pollution, ENO still maintains that the Council
must immediately approve NOPS for purported reliability reasons. 61 The Joint Intervenors argue
that none of ENO’s claimed reasons for building the gas plant, whether the original capacity
arguments or the new reliability arguments, justify the project and that ENO has failed to study
cheaper, faster, and less polluting means to resolve the reliability issues the City faces, and the
Council should reject ENO’s application; 62 and

57

Joint Intervenors’ Post-Hearing Brief at 4.
Joint Intervenors’ Post-Hearing Brief at 3-6.
59
Joint Intervenors’ Post-Hearing Brief at 7.
60
Joint Intervenors’ Post-Hearing Brief at 7-9.
61
Joint Intervenors’ Post-Hearing Brief at 9.
62
Joint Intervenors’ Post-Hearing Brief at 9-10.
58

19

 WHEREAS, the Advisors, having reviewed the evidence presented in this case and
performed their own, independent analyses, conclude that ENO’s customers are presently at
serious and unacceptable risk of significant electrical outages of potentially long duration and
such risk will persist until some form of reliable, fast-start generation is obtained locally. 63 The
Advisors believe only two of the options presented to the Council could address the identified
reliability and capacity needs -- the option to build a CT Alternative or the option to build the
RICE Alternative. 64 The Advisors do not believe that the third option -- to reject both proposals
and instead rely upon ENO’s ability to perform transmission upgrades to mitigate the reliability
concern and meet the capacity need with a combination of demand-side management (“DSM”),
distributed generation (“DG”) and renewable resources (the “Transmission Alternative”) is a
realistic, reliable, or prudent method of addressing the identified concerns; 65 and
WHEREAS, the Advisors argue that the RICE Alternative has many advantages over
both the CT Alternative and the Transmission Alternative: (1) because of its smaller size, the
RICE Alternative more closely fits ENO’s need; (2) it would use 95% less groundwater than the
CT Alternative and would represent a 99.9% reduction in groundwater usage compared to the
deactivated Michoud units previously operating at that site; and (3) it has black-start capability,
and would provide a local resource for ENO to respond to storm events and other types of
outages; 66 and
WHEREAS, the Advisors believe that the CT Alternative is too big and that the
Transmission Alternative is likely to be difficult-to-impossible to effectively implement in the
time frame needed and puts all of ENO’s eggs into one basket by leaving the City 100%
63
Post-Hearing Brief of the Advisors to the City Council of New Orleans, Docket No. UD-16-02, at 1 (Jan. 19, 2018)
(“Advisors’ Post-Hearing Brief”).
64
Advisors’ Post-Hearing Brief at 1.
65
Advisors’ Post-Hearing Brief at 1.
66
Advisors’ Post-Hearing Brief at 1-2.

20

 dependent upon the repair of transmission facilities to restore power after a blackout, which can
take days or even weeks to accomplish; 67 and
WHEREAS, the Advisors believe that the issues raised with respect to environmental
hazards, flooding, and subsidence should be fully addressed by conditioning the Council’s
approval upon compliance with all applicable federal, state, and local laws and recommend that
the Council should specifically require ENO to demonstrate such compliance by filing copies of
all permits obtained and any other rulings by any agency with authority over the project; 68 and
WHEREAS, the Advisors argue that the RICE Alternative is a proven technology that
many regulators are turning to in order to support the transition to renewables and ensure
reliability, and that quick-starting units such as the RICE units selected for the project are needed
to complement the technical advantages of existing units not only to ensure reliable power to
customers, but to enable the integration of more cost-effective variable renewable generation; 69
and
WHEREAS, the Advisors state that locating the plant at the Michoud site is a reasonable
choice by the utility, and the physical requirements of the system are best served by placing a
facility within a specific geographic location, within which, the Michoud site is the best suited to
meet the needs of the community for several reasons. 70 The Advisors also note that evidence in
the record indicates that the environmental impact on New Orleans East will be significantly
reduced compared to the impact of the plants previously operating at Michoud, and will remain
within the limits set by the Environmental Protection Agency (“EPA”) and the Louisiana
67

Advisors’ Post-Hearing Brief at 2. The Advisors note that recent news reports indicate that MISO asked utilities
in MISO South to encourage their customers to reduce usage to due to a potential shortage of capacity during a
recent weather event.
See http://www.fox8live.com/story/37291783/entergy-customers-free-to-use-power-asnormal and https://www.livingstonparishnews.com/entergy-asks-louisiana-customers-to-reduce-electricity-today-orface/article_d2233344-fc16-11e7-a0fa-4b9f1ae12321.html.
68
Advisors’ Post-Hearing Brief at 3.
69
Advisors’ Post-Hearing Brief at 4-5, citing to recent decisions in Michigan and Hawaii to approve RICE units.
70
Advisors’ Post-Hearing Brief at 5-6.

21

 Department of Environmental Quality (“LDEQ”). 71 Thus, the Advisors believe there will be no
disproportionate, significant adverse effect on residents of New Orleans East, and that there will
be significant benefits to them in terms of both electric reliability and economics. 72 Without the
plant, the Advisors believe there is substantial risk that multiple minority neighborhoods would
be at a serious and unacceptable risk of outages; 73 and
WHEREAS, the Advisors also argue that the Council’s process has provided sufficient
opportunity for public input regarding the plant; and that the matter is sufficiently ripe for
Council decision; 74 and
I.

Whether ENO’s analysis of need is sufficient to justify an investment

WHEREAS, ENO argues that it has both a long-term need for peaking capacity and that
it has had a current and persisting reliability need since the deactivations of Michoud Units 2 and
3; 75 and
A.

Whether ENO has demonstrated a capacity need

WHEREAS, ENO argues that the evidence confirms that ENO has an overall need for
long-term capacity, a substantial need for long-term peaking and reserve capacity, as well as
unique planning needs in New Orleans that justify construction of NOPS; 76 and
WHEREAS, ENO projects an overall need of approximately 99 MW of capacity by
2026, which grows to approximately 248 MW by 2036, the end of the 20-year planning
horizon. 77 ENO further states that its current forecast indicates a persistent peaking and reserve

71

Advisors’ Post-Hearing Brief at 6.
Advisors’ Post-Hearing Brief at 6.
73
Advisors’ Post-Hearing Brief at 6.
74
Advisors’ Post-Hearing Brief at 6-7.
75
ENO Post-Hearing Brief at 4-5.
76
ENO Post-Hearing Brief at 7.
77
ENO Post-Hearing Brief at 8; Supplemental and Amending Direct Testimony and Exhibits of Seth Cureington,
Docket No. UD-16-02, at 7, Ex. SEC-11(July 6, 2017) (HSPM) (“Cureington-6”).
72

22

 deficit of approximately 342 MW on average in each year of the 20-year planning horizon. 78
ENO has submitted evidence, including its load forecast and other analyses, to the Council in
support of this assertion; 79 and
WHEREAS, Air Products states that after reviewing the evidence, especially the
Supplemental and Amending Direct Testimony of ENO’s witness Cureington filed in July of
2017, Air Products concluded that there is a capacity deficit on the ENO system, and a need to
install additional capacity.

Air Products explains that the specific details supporting this

conclusion are set forth in Cureington’s Exhibit SEC-11, and that it is clear from a review of this
load and capacity statement that unless additional capacity is added to the ENO system, ENO
will have a large and persistent deficit and would not be able to meet its customers’ needs; 80 and
WHEREAS, Air Products states that its witness, Mr. Brubaker, noted that ENO’s
updated studies indicate a long-term capacity need of approximately 99 MW by 2026, and up to
248 MW by 2036, but that the 2036 data is a forecast almost 20 years into the future, and it is
very possible that the load will not grow as much as projected or that anticipated retirements of
power plants in Amite South will be delayed, or both, resulting in less need for capacity than
asserted by ENO; 81 and
WHEREAS, Air Products explains that it supports adding some capacity, but it does not
believe that the evidence justifies adding the 226 MW unit because there is not a near-term need
for this amount of capacity. 82 Air Products argues that the evidence shows that it is obvious that
adding the 226 MW CT Alternative would create a significant excess capacity for a prolonged

78

ENO Post-Hearing Brief at 8; Cureington-6 at 7, Ex. SEC-11.
Cureington-6 at 7, Ex. SEC-11.
80
Air Products Post-Hearing Brief at 5.
81
Air Products Post-Hearing Brief at 5, citing Additional Direct Testimony and Exhibits of Maurice Brubaker,
Docket No.UD-16-02, at 6:2-6 (Oct. 16, 2017) (“Brubaker-2”).
82
Air Products Post-Hearing Brief at 5.
79

23

 period of time and that it is not a suitable addition as reserve margins would increase
significantly above the 12% target. 83 Air Products argues that because of the large amount of
excess capacity it would create, the CT Alternative may not be considered used and useful by the
City Council. 84 Air Products’ witness Mr. Brubaker testified that, in light of the long time before
an indicated capacity need would approach 226 MW, a smaller amount of capacity added now
will cover needs in the near future, provide time to evaluate how loads actually materialize, and
allow stakeholders to monitor the need for and timing of unit retirements. 85 He also testified that
the smaller revenue requirement associated with a smaller capacity addition will also reduce risk
and create less of an impact on customers; 86 and
WHEREAS, Air Products also argues that the evidence shows that adding the 128 MW
RICE unit yields excess capacity as well, but not to the same extent as would be true if the CT
unit were added, and that the RICE Alternative, therefore, is a more appropriate fit for the needs
of ENO’s customers at this point in time; 87 and
WHEREAS, Air Products states that while it supports construction of a RICE facility, it
strongly encourages the Council not to approve initial construction of all seven of the 18 MW
Wärtsilä units because the evidence clearly indicates that not all of that capacity is needed
initially, and may not ever be needed. 88 Air Products recommends building out the infrastructure
to accommodate all seven units (in case all seven ultimately are needed), but installing only four
or five of the units now and deferring the decision to add other units until a later point in time

83

Air Products Post-Hearing Brief at 5-6, citing Excerpt of Ex. SEC-11 with handwritten notation of Peaker 226
MW (HSPM) (“AP-2”).
84
Air Products Post-Hearing Brief at 6.
85
Air Products Post-Hearing Brief at 6, quoting Brubaker-2 at 6:10-18.
86
Air Products Post-Hearing Brief at 6, quoting Brubaker-2 at 6:10-18.
87
Air Products Post-Hearing Brief at 6-7, citing Cureington-6, Ex. SEC-11, Brubaker-2 at 8:6-13, Direct Testimony
and Exhibits of Joseph Rogers, Docket No. UD-16-02, at 3:10-15 (Nov. 20, 2017) (“Rogers-1”).
88
Air Products Post-Hearing Brief at 9.

24

 when they may be justified. 89 Air Products argues that this will reduce the amount of capital
outlay and cost impact on customers and also provide time to learn how energy efficiency
measures and general demographic and economic conditions actually will impact ENO’s load
growth. 90 Air Products argues that it is very possible that if energy efficiency and demand
response efforts are successful under the Energy Smart program, that load growth will be less
than currently forecasted by ENO, and that ENO’s recent history of forecasts have demonstrated
lower load forecasts each time a forecast is made; 91 and
WHEREAS, Air Products argues that the evidence shows that fewer RICE units would
be more than sufficient to meet the anticipated needs for the first few years. 92 Air Products does
not find ENO’s argument that it would be a lower average cost per kW if all seven units are built
at once to be persuasive, arguing instead that it is uncertain that the additional units will ever be
needed, and therefore, it does not make sense to make a larger upfront dollar outlay when New
Orleans may never use the full capacity; 93 and
WHEREAS, NOCS argues that ENO’s showing falls far short of establishing a need for
226 MW of CT capacity, and is dubious with regard to whether ENO needs 128 MW of RICE
capacity. 94 NOCS notes that ENO’s projected need decreased between its Initial Application and
its Supplemental and Amending Application and that even under the most aggressive
assumptions, ENO does not have a need for over 200 MW of capacity until at least 2036, 20
years into the future. 95 NOCS notes that the further you go into the future, the less certain a

89

Air Products Post-Hearing Brief at 9.
Air Products Post-Hearing Brief at 9.
91
Air Products Post-Hearing Brief at 9.
92
Air Products Post-Hearing Brief at 9, citing to Hr’g Tr. 12/18/17, 330:7-331:19.
93
Air Products Post-Hearing Brief at 10.
94
NOCS Post-Hearing Brief at 4.
95
NOCS Post-Hearing Brief at 4.
90

25

 forecast is and that, while forecasts can err on the high side as well as the low side, the
established trend has shown load growth declining, not increasing; 96 and
WHEREAS, NOCS argues that the evidence shows that ENO’s load forecast is likely
overestimated and that the 2% DSM Goal, if achieved, and ENO’s commitment to add 100 MW
of renewables to its portfolio, if realized, could wipe out the entirety of the 99 MW shortfall
expected by 2026. 97 NOCS argues that the evidence supporting ENO’s 99 MW capacity need is,
therefore, weak at best; 98 and
WHEREAS, the Joint Intervenors argue that ENO has failed to establish that it will have
a capacity need for a $200 million gas plant at any point in the next 10 years. 99 They argue that
there is no capacity need to build a $200-plus million gas plant, and that the evidence shows that
even with the City’s continued economic and population growth ENO’s system is actually
moving toward a capacity surplus without the gas plant. 100 The Joint Intervenors argue that the
evidence shows that without building either gas plant proposed, by 2026, ENO will likely have a
capacity surplus, assuming that it installs 100 MW of solar capacity and achieves savings
consistent with the Council’s 2% DSM Goal, and that this will be an even greater surplus if New
Orleanians continue to install new residential or commercial solar at existing rates, rather than
halting new installations in 2020 as ENO unreasonably assumes; 101 and
WHEREAS, the Joint Intervenors argue that building the RICE units would raise the
capacity surplus and ENO customers would bear the full risk of paying for that extra capacity. 102
The Joint Intervenors argue that New Orleans has the time to focus on studying a more cost-

96

NOCS Post-Hearing Brief at 6.
NOCS Post-Hearing Brief at 6-7.
98
NOCS Post-Hearing Brief at 8.
99
Joint Intervenors’ Post-Hearing Brief at 10.
100
Joint Intervenors’ Post-Hearing Brief at 10.
101
Joint Intervenors’ Post-Hearing Brief at 11-12.
102
Joint Intervenors’ Post-Hearing Brief at 12.
97

26

 efficient set of progressive alternatives, potentially including further DSM, renewable energy and
bulk battery storage, and, as necessary, purchases on the MISO capacity market, to maintain
resource adequacy across the long term. 103 They argue that making a massive, $200-plus million
investment based on claimed shortfalls at the end of a 20-year period is particularly risky and
would be unnecessary, as the Council would have well over a decade in which to evaluate the
least-cost alternatives to meet any lingering, long-term need; 104 and
WHEREAS, the Joint Intervenors urge that, to the extent that ENO argues that there is a
foreseeable capacity need for a gas plant, ENO is relying on misleading assumptions or
suggesting it will not meet the Council’s energy efficiency goals. 105 The Joint Intervenors argue
that the Council should only consider ENO’s overall capacity need, and not its claim of a greater
peaking and reserve deficit, which the Joint Intervenors allege is “merely a slight of hand to
create the impression of a need;” 106 and
WHEREAS, the Joint Intervenors argue that ENO’s concern that the capacity it owns
could retire sooner than forecast, thereby reducing any capacity surplus, is speculative and
redundant in that ENO already projected retirement dates for its resources in its reference load
forecast, and the total amount that could retire early is less than the size of the RICE
Alternative; 107 and
WHEREAS, the Joint Intervenors argue that ENO’s load forecast is misleading because
it fails to account for any peak demand savings from new energy efficiency programs approved

103

Joint Intervenors’ Post-Hearing Brief at 12.
Joint Intervenors’ Post-Hearing Brief at 13.
105
Joint Intervenors’ Post-Hearing Brief at 12.
106
Joint Intervenors’ Post-Hearing Brief at 14.
107
Joint Intervenors’ Post-Hearing Brief at 14.
104

27

 by the Council after 2016, specifically the goals approved for Energy Smart Program Years 7-9,
which would double the savings; 108 and
WHEREAS, the Joint Intervenors argue that ENO’s position that the Council’s goals are
not “cost effective or achievable” is a misguided and inappropriate attempt to re-litigate the
Council’s recent energy efficiency proceeding, and that its extreme skepticism is contrary to the
evidence of its own experts and the City’s Climate Action Plan. 109 The Joint Intervenors also
take issue with ENO’s projection that ENO customers will no longer install new rooftop solar
panel systems after 2020 and goes against the trend of declining prices; 110 and
WHEREAS, the Joint Intervenors encourage the Council to examine the ENO 2018 load
forecast that is expected to be released soon before accepting ENO’s assertions that extra
capacity is needed; 111 and
WHEREAS, the Joint Intervenors argue that rather than building a gas plant, ENO
should meet any shortfall more cheaply with smaller resources, further investments in renewable
energy or bulk battery storage, or with MISO capacity market purchases; 112 and
WHEREAS, the Joint Intervenors also argue that building either gas plant will expose
New Orleans residents and businesses to significant financial risk and could limit the options to
invest in renewables or energy efficiency. 113 They argue that the evidence shows that in the

108

Joint Intervenors’ Post-Hearing Brief at 15.
Joint Intervenors’ Post-Hearing Brief at 15.
110
Joint Intervenors’ Post-Hearing Brief at 16-17.
111
Joint Intervenors’ Post-Hearing Brief at 17. The Council notes that in making this argument the Joint Intervenors
are urging it to rely upon evidence outside the record that other parties have had neither the opportunity to review or
conduct cross-examination on. The Council will not take into account evidence which is not properly in the record
of this case in rendering its decision.
112
Joint Intervenors’ Post-Hearing Brief at 18.
113
Joint Intervenors’ Post-Hearing Brief at 18.
109

28

 most likely scenarios, the ratepayer will pay significantly more than ENO claims for the surplus
capacity created by a gas plant; 114 and
WHEREAS, the Joint Intervenors argue that ENO’s projections of MISO capacity
market prices approaching the cost of new entry (“CONE”) are not supported by historical trends
or market fundamentals that further point to prices staying low due to capacity surpluses in
MISO. 115 The Joint Intervenors argue that if capacity prices remain low, New Orleans residents
and businesses will pay more than ENO has projected for excess capacity, and this risk is most
pronounced with the CT Alternative, though the RICE Alternative also presents a troubling level
of capacity market risk; 116 and
WHEREAS, the Joint Intervenors argue that the potential for New Orleans ratepayers to
over-pay for capacity poses a real social justice concern, given the energy burden borne by lowincome customers; 117 and
WHEREAS, the Joint Intervenors also argue that another risk in overbuilding gas
capacity is that doing so will reduce the incentive to invest instead in new sources of renewable
energy and DSM. 118 They argue that ENO’s witness Charles Rice stated that ENO’s witness
Charles Long specified that if ENO builds the RICE units, there would not be a foreseeable need
for additional generation such as renewables, in ENO’s system; 119 and
WHEREAS, the Advisors, after reviewing the evidence and performing their own
analysis, reached the conclusion that there is a capacity need that ENO needs to fill, and that it is
of sufficient size to warrant an investment in long-term capacity rather than relying upon short-

114

Joint Intervenors’ Post-Hearing Brief at 18.
Joint Intervenors’ Post-Hearing Brief at 19-20.
116
Joint Intervenors’ Post-Hearing Brief at 21.
117
Joint Intervenors’ Post-Hearing Brief at 21.
118
Joint Intervenors’ Post-Hearing Brief at 22.
119
Joint Intervenors’ Post-Hearing Brief at 22.
115

29

 term capacity acquisitions, even though the Advisors do concur that ENO has overestimated its
capacity need; 120 and
WHEREAS, the Advisors do not dispute the underlying methodology of ENO’s load
forecast, and the Advisors do not find it unusual that a load forecast would fluctuate over time. 121
The Advisors explain that the nature of a load forecast is to predict the future; there will always
be some over- or under-estimation, simply because no one can predict the future with great
precision (especially where consumption is partially dependent upon future weather
conditions). 122 The Advisors explain that the goal is to make a prediction based on known data
and reasonable assumptions that can reasonably be used for planning purposes; 123 and
WHEREAS, the Advisors nevertheless observe that the revised load forecasts illustrate a
general downward trend in expectations of how load will grow over time. 124 Although ENO
argues that there is still a need sufficient to justify its 226 MW CT Alternative, 125 the Advisors
believe that the significant reduction in projected total load requirements since the 2015 Final
IRP, where a 250 MW CT to come online in 2019 was selected as part of the preferred portfolio,
would strongly suggest that the 226 MW CT Alternative may be greater than the optimal size for
the proposed peaking plant on a capacity need basis; 126 and
WHEREAS, the Advisors note that Joint Intervenors’ witness Dr. Stanton argues that
properly accounting for ENO’s own planned solar investments reduces ENO’s claimed capacity

120

Advisors’ Post-Hearing Brief at 18-19.
Advisors’ Post-Hearing Brief at 19-20.
122
Advisors’ Post-Hearing Brief at 19-20.
123
Advisors’ Post-Hearing Brief at 18-19.
124
Advisors’ Post-Hearing Brief at 22, citing Supplemental and Amending Direct Testimony and Exhibits of Seth
Cureington, Docket No. UD-16-02, at 7:3-6 (July 6, 2017) (“Cureington-5”), Rogers-1 at 6:17-7:1, and Direct
Testimony and Exhibits of Joseph Rogers, Docket No. UD-16-02, at 7:1-3 (Nov. 20, 2017) (HSPM) (“Rogers-2”).
125
Cureington-5 at 11:10-12:14.
126
Advisors’ Post-Hearing Brief at 22, citing Rogers-1 at 9:3-6.
121

30

 deficit from 99 MW in 2026 to 49 MW. 127 The Advisors explain that Dr. Stanton bases this
conclusion on ENO’s announcement that it is planning to procure 100 MW of utility-scale solar
resources that will come online in 2020 and half of which MISO credits toward capacity, which
she believes would result in a 50 MW reduction in ENO’s capacity need. 128 However, the
Advisors note that upon cross-examination, Dr. Stanton admitted that she does not know the
location of any of the potential 100 MW of renewables; 129 and
WHEREAS, ENO states that while ENO remains committed to adding up to 100 MW of
solar, the timing and location of those resources are still uncertain. 130 ENO argues that NOPS
has been identified as the best alternative to meet the Company’s long-term overall capacity
deficit, including the substantial need for a local peaking and reserve resource that would provide
the benefits ENO discusses with respect to NOPS; 131 and
WHEREAS, with respect to the Joint Intervenors’ argument that ratepayer investment in
rooftop solar is likely to continue to grow in a linear fashion, in cross-examination, Joint
Intervenors’ witness Dr. Stanton admitted that (1) she had not performed any analysis that
supports this trajectory of behind-the-meter solar growth in New Orleans; 132 (2) that she did not
perform an analysis with respect to the duration that behind-the-meter or utility scale battery
storage could provide capacity when needed; 133 (3) and that she did not perform an analysis of
the potential costs of either behind-the-meter solar or utility scale battery storage over the 20-

127

Advisors’ Post-Hearing Brief at 23, citing Direct Testimony and Exhibits of Dr. Elizabeth Stanton, Docket No.
UD-16-02, at 6:7-8 (Oct. 16, 2017) (“Stanton-1”).
128
Advisors’ Post-Hearing Brief at 23-24, citing Stanton-1 at 11:8-14.
129
Advisors’ Post-Hearing Brief at 24, citing In re. Supplemental and Amending Application of Entergy New
Orleans, Inc., Hearing Transcript, Docket No. UD-16-02 (Dec. 21, 2017), 22:4-15 (“Hr’g Tr. 12/21/17”).
130
Advisors’ Post-Hearing Brief at 24, citing Cureington-7 at 49:15-16.
131
Advisors’ Post-Hearing Brief at 24, citing Cureington-7 at 49:4-9.
132
Advisors’ Post-Hearing Brief at 24, citing Hr’g Tr. 12/21/17, 24:11-15.
133
Advisors’ Post-Hearing Brief at 24, citing Hr’g Tr. 12/21/17, 25:17-22.

31

 year planning horizon, and had not analyzed the capacity that either could provide. 134 Given her
lack of analysis to support her projections of behind-the-meter solar growth in New Orleans, the
Advisors are not persuaded to rely upon her calculation of how much capacity is likely to be
available through behind-the-meter solar; 135 and
WHEREAS, the Advisors note that, in addition to not incorporating the 2% DSM Goal
into its reference case, a review of ENO’s calculations indicates that while ENO accounted for
the effects of existing DSM programs for Program Year 6 (12 months ended March 2017), it did
not incorporate any reductions in the load requirements for future DSM programs. 136

The

Advisors’ analysis shows that if the 2% DSM Goal is taken into account in the load forecast, the
projected capacity shortfall is lower than ENO forecasts. 137 The Advisors do find it important,
however, that ENO has submitted evidence backed by a study performed by Navigant Consulting,
Inc. (“Navigant”) that the 2% DSM Goal is not achievable and no party has put evidence into the
record that demonstrates that the 2% DSM Goal is achievable. The Advisors believe that it is
reasonable, in light of the goal, to expect the kWh savings from DSM to grow beyond the
Program Year 6 kWh savings assumed in ENO’s reference case, and thus, the Advisors believe
that the ultimate capacity need will likely be smaller than what ENO has projected. 138
Accordingly, the Advisors conclude that a capacity need exists, albeit smaller with consideration
of DSM growth, and the Advisors believe that a long-term investment in generation capacity is
justified; 139 and

134

Advisors’ Post-Hearing Brief at 24-25, citing Hr’g Tr. 12/21/17, 24:22-25:16.
Advisors’ Post-Hearing Brief at 25.
136
Advisors’ Post-Hearing Brief at 27, citing Rogers-1 at 10:1-5; Direct Testimony and Exhibits of Victor Prep,
Docket No. UD-16-02, at 30:2-5 (Nov. 20, 2017) (“Prep-1”).
137
Advisors’ Post-Hearing Brief at 27, citing Rogers-2 at 13:7-11.
138
Advisors’ Post-Hearing Brief at 27-28.
139
Advisors’ Post-Hearing Brief at 28.
135

32

 WHEREAS, the Advisors’ analysis demonstrates that ENO has employed inconsistent
peak load assumptions between its transmission studies and economic studies when considering
the amount of DSM peak load reductions which would occur with the continued implementation
of the Council’s 2% DSM Goal and the appropriate capacity factor of any potential solar
generation. 140 The Advisors explain that such inconsistent assumptions can affect the actual load
to be served in the transmission studies in the range of 48.1 MW to 63.1 MW over the period
analyzed; 141 and
WHEREAS, the Advisors state that, there is significant uncertainty as to by how much
ENO’s load forecast can reasonably be reduced. 142 The Advisors urge that reliable electric
service is a critical need, the consequences of failing to ensure reliable service -- in this case the
potential for cascading outages of potentially long duration affecting as many as 49,000
customers -- are likely to be worse than the consequences of investing in slightly too much
capacity. 143 The Advisors recommend the installation of an amount of capacity that allows for a
reasonable margin of error, based on the data and information known at this time. 144 The
Advisors state that it is generally not possible to match capacity with load requirements
precisely, any given utility will be somewhat long or short on capacity in any given year, and
using the capacity markets as a short-term fix to true up any such minor imbalances is
reasonable. 145 However, capacity market prices are variable, and because of this, the Advisors
find that it is prudent to try to match the capacity with the load requirement as closely as is
reasonably possible; 146 and

140

Advisors’ Post-Hearing Brief at 28-29, citing Vumbaco-1 at 6:12-15.
Advisors’ Post-Hearing Brief at 29, citing Vumbaco-1 at 6:15-17.
142
Advisors’ Post-Hearing Brief at 29.
143
Advisors’ Post-Hearing Brief at 29.
144
Advisors’ Post-Hearing Brief at 29.
145
Advisors’ Post-Hearing Brief at 29.
146
Advisors’ Post-Hearing Brief at 29, citing Rogers-1 at 32:1-8.
141

33

 WHEREAS, the Advisors conclude that the evidence indicates that ENO has an
immediate and future need for capacity and that need is not mitigated even if the Council’s 2%
DSM Goal is achieved. 147 Further, the Advisors believe that it would not be appropriate to rely
on the MISO annual planning resource auction (“PRA”) to meet ENO’s long-term resource
needs. 148 Accordingly, the Advisors believe the capacity need in combination with the reliability
need warrants an investment in long-term capacity; 149 and
WHEREAS, ENO asserts that the Joint Intervenors’ witnesses propose a number of
speculative and unreasonable assumptions intended to erode the Company’s capacity estimates
and undermine its economic analysis to make the Transmission Alternative look more attractive.
ENO argues that they altered reasonable assumptions in order to lower ENO’s load and the price
of capacity in the MISO market based on pure speculation and without any production cost or
capacity expansion modeling and without having reviewed any of the analysis performed in the
2015 Final IRP proceeding; 150 and
WHEREAS, ENO argues that the Joint Intervenors’ witnesses’ proposed reductions to
ENO’s peak load forecast are unreasonable. 151

ENO argues that if it were to adopt Joint

Intervenors hypothetical assumptions and manipulations of the numbers, it could lead to the
Company not planning for load that will in fact materialize, “which has a host of negative
consequences; 152 and
WHEREAS, ENO points out that both Dr. Stanton and Mr. Fagan admitted at the
hearing that they do not have any complaints about the fundamental methodology used by ENO

147

Advisors’ Post-Hearing Brief at 29.
Advisors’ Post-Hearing Brief at 29.
149
Advisors’ Post-Hearing Brief at 29.
150
ENO Post-Hearing Brief at 17-18.
151
ENO Post-Hearing Brief at 19-31.
152
ENO Post-Hearing Brief at 19.
148

34

 to forecast its peak load, and that they did not provide any alternative load forecast of their
own. 153 ENO also points out that Mr. Fagan admitted that he has never created a load forecast
for resource planning; 154 and
WHEREAS, ENO states that it supports the Council’s 2% DSM Goal, but argues that it
is extremely aggressive and that no party in this case can guarantee that it will be achieved, and
that it would warp the results of any resource planning that relies on it as a basis for estimating
the amount of load that is expected to materialize; 155 and
WHEREAS, ENO argues that Joint Intervenors’ witness Dr. Stanton admitted at the
hearing that she did not conduct any analysis of the DSM potential in New Orleans; 156 and
WHEREAS, ENO criticizes the Joint Intervenors’ witnesses reliance upon comparisons
to DSM levels achieved in other, primarily Northeastern states, without attempting to determine
whether ENO is comparable to any of the higher-achieving states. 157 ENO argues that DSM
savings can be affected by different utility avoided costs, different retail rates, different maturity
in energy efficiency work force, and different customer mixes. 158 ENO argues that the evidence
indicates that the level of DSM savings actually achieved by states in geographic proximity to
Louisiana is much lower, ranging from 0.06% to 0.39% across nine southeastern states,
compared to ENO’s 0.34% achievement; 159 and

153

ENO Post-Hearing Brief at 19, citing Supplemental and Amending Application of Entergy New Orleans, Inc.,
Hearing Transcript, Docket No. UD-16-02, 20-21 (Dec. 19, 2017) (“Hr’g Tr. 12/19/17”) and Hr’g Tr. 12/21/17, 2021.
154
ENO Post-Hearing Brief at 19, citing to Hr’g Tr. 12/19/17, 23 and Excerpt of Ex. SEC-11 with handwritten
notation of Wärtsilä 128 MW (HSPM) (“AP-3”).
155
ENO Post-Hearing Brief at 19-20.
156
ENO Post-Hearing Brief at 20, citing Hr’g Tr. 12/21/17, 22.
157
ENO Post-Hearing Brief at 21.
158
ENO Post-Hearing Brief at 21, citing Rebuttal Testimony and Exhibits of Seth Cureington, Docket No. UD-1602, at 29 (Nov. 30, 2017) (HSPM) (“Cureington-8”).
159
ENO Post-Hearing Brief at 19-21, citing Cureington-8, Ex. SEC-20.

35

 WHEREAS, ENO retained Navigant to assess the achievability and cost-effectiveness of
the Council’s 2% DSM Goal. 160 ENO reports that Navigant concluded in its report that, while it
is possible, in academic theory to achieve 2% savings from energy efficiency measures in New
Orleans, the assumptions required to force their proprietary DSM simulator model to solve for 2%
annual savings in New Orleans were theoretical and required Navigant to relax industry standard
thresholds for cost-effectiveness, incentive levels, administrative costs, and market saturation
and further assume that new measures not in existence today will be invented and available at
some unknown future date. 161 ENO states that under those highly theoretical and arguably
unreasonable assumptions, Navigant essentially forced its model to produce the 2% aspirational
goal and estimated a price tag of $2.3 billion over the planning horizon. 162 ENO argues that
using such assumptions in its long-term resource planning is not reasonable; 163 and
WHEREAS, ENO argues that the Joint Intervenors are also incorrect that ENO should
have used at least Navigant’s “High Case Achievable Scenario” savings level of 0.85% in
calculating its peak load forecast. 164 ENO argues that this case represents a ceiling as to what
might be possible, and not a floor, and therefore it is not appropriate to utilize that figure in
preparing ENO’s forecast of the load it will realistically be required to serve; 165 and
WHEREAS, ENO also argues that there is no basis upon which to conclude that DSM
can meet the need that exists today because DSM takes time to accumulate. 166 ENO states that it
would likely take 10-20 years to get to the level of demand response that ENO needs to even get
close to the identified needs. ENO argues that it has included the forecasted effects of Energy

160

ENO Post-Hearing Brief at 21.
ENO Post-Hearing Brief at 21-22, citing Cureington-6, Ex. SEC-14.
162
ENO Post-Hearing Brief at 21-22, citing Cureington-6, Ex. SEC-14.
163
ENO Post-Hearing Brief at 21-22, citing Cureington-6, Ex. SEC-14.
164
ENO Post-Hearing Brief at 22-23.
165
ENO Post-Hearing Brief at 22-23.
166
ENO Post-Hearing Brief at 23.
161

36

 Smart programs through Program Year 6, the last full year for which data is available, and that to
make additional, speculative reductions would be unreasonable given the number of uncertain
factors already embedded in the forecast. 167 ENO also points out that they have included an
annual reduction in projected sales that reaches 1.5% in 2022 to account for the anticipated but
uncertain effects of the proposed deployment of Advanced Metering Initiative (“AMI”), and that
its load forecast does not include any adjustments for potential increases that could occur due to
faster-than-projected growth or adoption of electric vehicles (“EVs”) by customers. 168 ENO also
argues that the forecast assumes existing rooftop solar will continue providing the same level of
load reduction and similarly does not account for potential decreases in the rated capacity of
existing resources; 169 and
WHEREAS, ENO also objects to the Joint Intervenors argument that ENO’s projections
of continued growth in behind-the-meter solar are understated, and that ENO should assume a
greater reduction in peak load due to those resources. 170 ENO argues that the historical factors
driving behind-the-meter solar growth have changed and as a result, it will not continue to grow
at a rate similar to past growth. 171 ENO explains that initial growth was spurred by federal and
state tax credits that covered up to 80% of the cost of a typical rooftop solar system and a net
metering tariff allowing customers to sell excess energy back to ENO. 172 ENO notes that neither
Dr. Stanton nor Mr. Fagan did any analysis of the potential continued growth of behind-themeter rooftop solar in New Orleans. 173 ENO argues that going forward, it reasonably expects
that the number of new installations will continue to decrease to a de minimus point following

167

ENO Post-Hearing Brief at 23-24.
ENO Post-Hearing Brief at 25.
169
ENO Post-Hearing Brief at 26.
170
ENO Post-Hearing Brief at 27.
171
ENO Post-Hearing Brief at 27, citing Cureington-8 at 38.
172
ENO Post-Hearing Brief at 27, citing Cureington-8 at 39.
173
ENO Post-Hearing Brief at 27, citing Hr’g Tr. 12/19/17, 27 and Hr’g Tr. 12/21/17, 23-25.
168

37

 expiration of the existing state tax credit at the end of 2017, the phase-down of federal tax credits
that will begin in 2020 and, ultimately, will significantly reduce subsidies to customers and
installation companies; 174 and
WHEREAS, ENO also opposes the Joint Intervenors’ assertion that it failed to properly
account for ENO’s commitment to 100 MW of solar resources. 175 ENO argues that according to
ENO’s witness Cureington’s analysis, including both the 100 MW of planned solar resources and
the 128 MW RICE unit still results in a capacity deficit at the end of the 20-year period of 70
MW. 176 ENO also argues that building the CT unit in addition to the 100 MW of renewables
results in a capacity excess of only 28 MW at the end of the 20-year planning period, and that
carrying some excess capacity during the planning period is not unreasonable. 177 ENO believes
that the additional capacity associated with the larger CT Alternative would provide additional
benefits to mitigate market- and supply-related risks, which ENO argues is reasonable in
consideration of ENO’s unique planning circumstances, and the smaller RICE units would
provide similar benefits over the first half of the planning horizon; 178 and
WHEREAS, ENO also argues that including solar resources as “existing resources” in
the Company’s load and capability forecast is not reasonable because, although the Company is
committed to adding up to 100 MW of solar resources to its portfolio, the timing and location of
those resources are uncertain. ENO urges that even more important is that, regardless of location
and timing, witness Cureington explained that solar resources simply will not meet the
Company’s peaking capacity need; 179 and

174

ENO Post-Hearing Brief at 27, citing Cureington-8 at 40.
ENO Post-Hearing Brief at 29.
176
ENO Post-Hearing Brief at 29.
177
ENO Post-Hearing Brief at 29.
178
ENO Post-Hearing Brief at 30.
179
ENO Post-Hearing Brief at 30-31, citing Hr’g Tr. 12/18/2017, 327-328.
175

38

 WHEREAS, ENO argues that the parties opposing NOPS offer unreasonable speculation
to manipulate future MISO capacity prices in an attempt to undermine the Company’s economic
analysis. 180 ENO explains that one of the components of its economic analysis is a projection of
future MISO PRA clearing prices, which is based on an assumption that as equilibrium of supply
and demand occurs and excess capacity in the market tightens, capacity prices in MISO will
trend upwards and eventually reach the CONE. 181 ENO argues that this is the law of supply and
demand, and that Air Products witness Brubaker and Joint Intervenors’ witness Dr. Stanton
conceded that capacity prices would rise as the surplus decreases. 182 As ENO notes, however,
Joint Intervenors’ witnesses Mr. Fagan and Dr. Stanton dispute that equilibrium is likely to occur,
and they believe that prices in MISO will stay low; 183 and
WHEREAS, ENO argues that Dr. Stanton depends upon Mr. Fagan’s price projections,
and that Mr. Fagan’s position that the current surplus will continue indefinitely is contrary to the
credible evidence, rests on unwarranted speculation about potential future projects that may be
constructed by other utilities in MISO over which neither the Company nor the Council has any
control, and unreasonably relies on historical MISO PRA clearing prices that are not indicative
of the future and are influenced by a flawed capacity market and a current capacity surplus;184
and
WHEREAS, ENO argues that Mr. Fagan ignores that the projected surplus in the MISO
report that he cites could be undone by a single plant retiring early, and that there are over 3,200
MW of aging legacy resources in MISO Local Resource Zone (“Zone”) 9 that could deactivate
earlier, and that he ignores the importance of a narrow committed capacity margin in favor of
180

ENO Post-Hearing Brief at 31.
ENO Post-Hearing Brief at 31.
182
ENO Post-Hearing Brief at 31-32.
183
ENO Post-Hearing Brief at 31-32.
184
ENO Post-Hearing Brief at 32.
181

39

 focusing on “potential” capacity additions without any evidence of the likelihood of such
additions. 185 ENO argues that closing one’s eyes to risk and hoping for the best is not prudent
resource planning; 186 and
WHEREAS, ENO argues that its projection of equilibrium occurring around 2022 is
consistent with highly credible sources such as the MISO’s own projections of resource
adequacy, the 2016 North American Electric Reliability Corporation’s (“NERC”) long-term
reliability assessment, the MISO Independent Market Monitor (“IMM”), and IHS Market’s
annual capacity value forecast for MISO. 187 ENO argues that it is more reasonable to rely upon
these sources than on Mr. Fagan’s speculation; 188 and
WHEREAS, ENO also states that there are several flaws with Mr. Fagan’s reliance upon
historically low MISO PRA clearing prices as evidence of a continuing capacity surplus. 189 First,
ENO argues it is not reasonable to rely on short-term annual purchases of capacity credits
through the PRA to address long-term needs. 190 Second, ENO argues that it is illogical to
assume that one year’s clearing price is any indication of the next year’s price. 191 Third, ENO
argues that it is not surprising that, in general, historical PRA clearing prices in MISO South
have been low, and that it is undisputed that there is currently a capacity surplus in MISO, but
the evidence shows this surplus will not continue in perpetuity. 192 Fourth, ENO argues that it is
not reasonable to rely on historically low MISO PRA prices because, according to the MISO
IMM 2016 State of the Market Report, the demand for capacity in the PRA continues to poorly

185

ENO Post-Hearing Brief at 32-33.
ENO Post-Hearing Brief at 34.
187
ENO Post-Hearing Brief at 34-35, citing the 2017 MTEP Resource Adequacy Report (Book 2) and Cureington-8,
Exs. SEC-15, SEC-17, SEC-18 and SEC-19.
188
ENO Post-Hearing Brief at 35.
189
ENO Post-Hearing Brief at 35.
190
ENO Post-Hearing Brief at 36.
191
ENO Post-Hearing Brief at 36.
192
ENO Post-Hearing Brief at 36.
186

40

 reflect its true reliability value, which undermines its ability to provide efficient signals for
investment and retirement decisions; 193 and
WHEREAS, ENO argues that the MISO IMM 2016 State of the Market Report noted
that the addition of fast-start capacity in the Narrow Constrained Areas in MISO South would be
extremely valuable, and Mr. Fagan admitted at the hearing that he has not reviewed the report,
nor was he familiar with narrow constrained areas in MISO or aware of whether New Orleans
was in a narrow constrained area, which it is; 194 and
WHEREAS, ENO also disagrees that Advisors’ witness Mr. Rogers’ sensitivity analysis
using a $6/kW-year capacity price that remains essentially flat over the 20-year planning horizon
provides useful information, and argues that it should not be given any weight; 195 and
WHEREAS, ENO argues that regardless of the outcome of the economic evaluation, the
Transmission Alternative would not provide the reliability benefits needed by New Orleans and
would not meet the identified need for a local source of peaking and reserve capacity; 196 and
WHEREAS, the Council acknowledges that the evidence in the record indicates that the
2% DSM Goal may be unachievable.

However, the Council has retained an independent

consultant to conduct its own DSM Potential Study to determine the appropriate amount of costeffective DSM that the Council should pursue as a long-term goal. In addition, the Council for
the reasons set forth by the Intervenors and Advisors above, believes that ENO most likely has
underestimated the cost savings that will be achieved through energy efficiency in its
calculations of how much capacity it will need; and

193

ENO Post-Hearing Brief at 37.
ENO Post-Hearing Brief at 37, citing Cureington-8, Exs. SEC-15 at 15, 18.
195
ENO Post-Hearing Brief at 38.
196
ENO Post-Hearing Brief at 40.
194

41

 WHEREAS, on the other hand, given the uncertainty about precisely how much energy
efficiency will be achieved, the inability of any party to state with reasonable certainty how
much capacity will be offset by energy efficiency, and the Council’s obligation to assure reliable
electric service to New Orleans, the Council does not believe it would be prudent at this time to
require ENO to rely upon achieving the 2% DSM Goal for its long-term planning purposes or to
defer the acquisition of additional capacity based on the assumption that the 2% DSM Goal will
be reached; and
WHEREAS, the Council finds that the evidence in the case seems to indicate that there
will most likely be energy efficiency savings at a level somewhere between ENO’s projection
that assumes no new savings beyond what was implemented in Energy Smart Program Year 6
and the level that would occur if the 2% DSM Goal was met; and
WHEREAS, the Council believes that the various MISO capacity price forecasts and
analyses presented by the parties bracket the possible outcomes, with the high end being what
would happen if MISO capacity prices approach CONE and the low end being what would
happen if they remain at their historically low levels. The Council concludes that the testimony
in this case indicates that if the MISO capacity market prices escalate significantly, the CT
Alternative would be the most cost-effective alternative, while if prices stay low, the
Transmission Alternative would be the most cost-effective, both of which enhance the risk to
ratepayers should such forecasts not materialize. However, it appears that the anticipated costs
of both of these options swing widely as MISO capacity prices rise and fall, making them much
more expensive when capacity prices go in the other direction. The Council notes, as the record
demonstrates, 197 the RICE Alternative, is less dependent upon MISO capacity prices to support
its economics thus reducing ratepayer risk and, it remains relatively more predictable as MISO
197

Rogers-1, at 42, 44.

42

 capacity prices fluctuate. Therefore, there is less risk if forecasts of the direction of MISO
capacity prices that prove incorrect with the RICE Alternative than with either the CT
Alternative or the Transmission Alternative; and
WHEREAS, the Council concludes that the weight of the evidence demonstrates that
ENO has shown an immediate and future need for peaking and reserve capacity that is not
mitigated even if the Council’s 2% DSM Goal is achieved. In light of the known volatility of
MISO capacity market prices, the Council also agrees with ENO and the Advisors that it would
not be appropriate for ENO to rely on the MISO capacity market to meet its long-term resource
needs; and
B.

Whether ENO has demonstrated a reliability need

WHEREAS, ENO argues that the evidence in this case clearly shows that the City of
New Orleans faces current and persisting reliability risks since the deactivation of the Michoud
units in June 2016. If left unmitigated, these risks have the potential to produce devastating and
highly disruptive consequences including the possibility of cascading outages resulting from
certain transmission contingencies and the inability to restore power quickly following a
hurricane or other event causing the incoming transmission lines to ENO to fail and ENO’s
system to be islanded; 198 and
WHEREAS, ENO asserts that NOPS is the only reliable way to mitigate these concerns
because the Council can have a high degree of confidence that it can actually be constructed; and
that it can be constructed on an expedited basis. ENO contends that constructing the RICE
Alternative will not only mitigate the risk of widespread outages, but will also provide local

198

ENO Post-Hearing Brief at 40.

43

 generation for hurricane responses, black-start capability, reactive power, and create the ability
for at least some economic growth in the City of New Orleans; 199 and
WHEREAS, ENO urges the Council to disregard Joint Intervenors’ wait-and-see
approach, which is supported by witnesses who have no experience with the New Orleans
transmission grid or with hurricane restoration efforts; who have never been responsible for
serving utility customers reliably; and whose proposed alternatives are speculative; 200 and
WHEREAS, ENO takes issue with Joint Intervenors’ suggestion that it rely on load
shedding to address the reliability concerns; 201 and
WHEREAS, ENO explains that over the past 10 years, New Orleans went from having
three generating units within its borders to zero units, with the last two units retiring in June 2016.
The transmission topology in DSG, however, which was designed to be supported by
strategically placed generation in its center, and at its western and eastern (New Orleans) edges,
has not materially changed. 202 DSG is a “load pocket,” and the City is particularly sensitive to
reliability issues because of its location on a physical and electrical peninsula, with limited
transmission facilities that can import power into New Orleans. 203 Without generation in the
City, the transmission system has been increasingly stressed, leading to the risk of overloading
and cascading blackouts over large segments of the City; 204 and
WHEREAS, ENO asserts that a new dispatchable local generator to replace some of the
generation lost with the deactivation of Michoud is the only viable option to address the
reliability problem facing New Orleans; 205 and

199

ENO Post-Hearing Brief at 40, 60-64.
ENO Post-Hearing Brief at 41.
201
ENO Post-Hearing Brief at 48.
202
ENO Post-Hearing Brief at 42-43.
203
ENO Post-Hearing Brief at 42.
204
ENO Post-Hearing Brief at 43, 51-53.
205
ENO Post-Hearing Brief at 45.
200

44

 WHEREAS, ENO notes that the reliability problem that came about with the retirement
of Michoud, which even Joint Intervenors concede exists, 206 would normally trigger NERC
violations, however it is not presently in violation of NERC standards because it has a corrective
action plan in place which is the NOPS proposal; 207 and
WHEREAS, ENO argues that it needs a minimum of 128 MW of capacity. The 128
MW RICE Alternative would mitigate most of ENO’s reliability issues until 2027, when
transmission upgrades or the addition of one additional RICE unit might also be needed. 208 Until
2027, the 128 MW RICE Alternative would unload all of the transmission lines in the DSG,
making it more likely that the Company could get a transmission outage in 2027 to make
upgrades, if necessary; 209 and
WHEREAS, ENO points out that no party seriously contested that having local
generation in a storm-prone area is imperative to quick restoration of service. 210

This is

particularly crucial, ENO argues, when damage to the transmission system impedes restoration
efforts until the transmission system can be repaired. Having a local resource can provide an
alternative source of power to the distribution system over shorter distances of transmission.
ENO cites Hurricane Gustav as a recent example where this proved true. 211 ENO points out that
the Advisors, Air Products and Joint Intervenors’ witnesses are in agreement on this; 212 and
WHEREAS, ENO states that it is undisputed that a unit with black-start capability could
prove vital if the grid goes totally dark; 213 and

206

ENO Post-Hearing Brief at 44-45, 47.
ENO Post-Hearing Brief at 46.
208
ENO Post-Hearing Brief at 49.
209
ENO Post-Hearing Brief at 50.
210
ENO Post-Hearing Brief at 55.
211
ENO Post-Hearing Brief at 57-58.
212
ENO Post-Hearing Brief at 56.
213
ENO Post-Hearing Brief at 55-60.
207

45

 WHEREAS, ENO urges the Council that transmission upgrades alone are not a viable
alternative. There are extraordinary constructability problems associated with the transmission
upgrades, not the least of which are that (1) the risk of cascading outages would increase
dramatically, and (2) the ability to obtain necessary outages may be insurmountable. 214 In the
first half of 2017 alone, nine transmission outages were denied. 215 ENO witness Charles Long
estimated that construction of the five upgrades that would be needed if no generation were
constructed in New Orleans could take 8 to 10 years, and construction of even one line could
take several years. Mr. Long explained that this is because in the first year of the project, the
Company would take the first line out for a month in the fall and then a month in the spring, and
the process would be repeated for several years until the project is completed. The outage for
one project might be 12 months, but you cannot take a line out of service for 12 months straight,
because the outage can only occur at the lowest load times. 216 Witnesses for Joint Intervenors
and for the Advisors each acknowledged the difficulties ENO would face in trying to construct
transmission. 217 And if ENO could not get the outages, it would need to build along new
transmission paths, which has other challenges that would add time and costs to the project; 218
and
WHEREAS, ENO says that the Joint Intervenors have not, and cannot, offer any analysis
that supports the feasibility of constructing any of the upgrades in an accelerated manner, while it
is uncontested that NOPS can be constructed without needing to take any extended transmission
outages; 219 and

214

ENO Post-Hearing Brief at 65.
ENO Post-Hearing Brief at 65.
216
ENO Post-Hearing Brief at 65.
217
ENO Post-Hearing Brief at 66-67.
218
ENO Post-Hearing Brief at 66-67.
219
ENO Post-Hearing Brief at 66-67.
215

46

 WHEREAS, ENO also objects to Joint Intervenors’ other proposed approaches to the
reliability problem as speculative and unsubstantiated. The Joint Intervenors advocate increased
solar, increased load reductions over time (energy efficiency), and increased demand response,
either alone or in combination. 220 But none of these, according to ENO, has been shown to be an
effective solution to the pressing reliability issue. ENO notes that Joint Intervenors’ witness Mr.
Fagan, who does not have electrical engineering or transmission planning experience, conducted
no assessment to determine what combination of resources might address ENO’s reliability
needs. 221 Nor did Joint Intervenors’ witness Mr. Lanzalotta, who has no experience in Louisiana,
conduct any independent analysis about the likelihood that increased energy efficiency might
address ENO’s reliability issues. 222 However, ENO did conduct at reliability analysis, including
implementation of the Council’s full 2% DSM Goal, and the results showed that there still was
risk of cascading outages; 223 and
WHEREAS, with respect to the addition of solar to ENO’s system, ENO argues that Mr.
Lanzalotta agreed with ENO that the amount of solar that is added depends on customer behavior.
ENO points out that Mr. Lanzalotta had done no independent analysis regarding the ability of
distributed resources to affect the reliability issues in New Orleans. 224 Further, there is not
enough land in New Orleans East to install the 200 MW of solar that Joint Intervenors advocate
as a solution. Mr. Lanzalotta also had not done any independent analysis of the potential of
DSM to address reliability, which Joint Intervenors also advocate. 225

ENO notes that Air

Products agrees that there are limits to DSM, including that there are only a few customers that

220

ENO Post-Hearing Brief at 70.
ENO Post-Hearing Brief at 71.
222
ENO Post-Hearing Brief at 71.
223
ENO Post-Hearing Brief at 72.
224
ENO Post-Hearing Brief at 72-73, 82-83.
225
ENO Post-Hearing Brief at 73.
221

47

 can accept interruptible power, and in any event, ENO witness Mr. Charles Long and Advisors’
witness Mr. Movish concluded that curtailing the current interruptible customers would not solve
the reliability problem; 226 and
WHEREAS, ENO states that reliance on other planned generators in the region will not
alleviate the reliability issue. ENO already included all generators planned in the region in its
analysis, and concluded that they do not eliminate the risk of cascading outages. 227

And

upgrading auto-transformers within ENO’s service territory, or installing battery storage, are not
viable solutions. ENO would be unlikely to get the outage needed to upgrade auto-transformers,
and doing so would create “extraordinary risks” to the electric grid. 228 And there is nothing in
the record that would indicate that battery storage would address the reliability issue. Among
other challenges, batteries have limited usefulness (only about four hours of charge), and they are
net loads, not generators (i.e., they consume more power than they discharge); 229 and
WHEREAS, Air Products agrees that ENO has a reliability need. Specifically, Air
Products states that ENO witness Mr. Charles Long addressed local reliability needs in his
Supplemental and Amending Direct Testimony and noted that Mr. Charles Long testified that
“[b]y 2019, if NOPS is not constructed, several 230 kV and 115 kV lines in DSG would overload
without additional transmission investment. In addition, a Category P6 contingency event would
result in severe overloads of several 115 kV lines in the DSG area, leading to uncontrollable
cascading outages of up to six 115 kV transmission branches. Consequently, a voltage collapse
and load shed event in the ENO transmission network would result from the severe reactive
power deficit due to the loss of the transmission branches and reactive power support in the ENO

226

ENO Post-Hearing Brief at 74-75.
ENO Post-Hearing Brief at 76.
228
ENO Post-Hearing Brief at 76-77.
229
ENO Post-Hearing Brief at 78-79.
227

48

 transmission grid. Also in 2019, a breaker failure contingency at the Ninemile 230 kV substation
was observed to result in three 230 kV transmission line overloads and one 115 kV transmission
line overload;” 230 and
WHEREAS, further relying on the testimony of ENO witness Mr. Charles Long, Air
Products explains that unless generation capacity is constructed in the ENO service territory, the
amount of transmission investment that would be necessary to address reliability concerns
exceeds $50 million – assuming that it would be possible to site the necessary transmission lines
in wetlands and heavily populated areas, complicated further by soil conditions ill-suited for
construction of transmission infrastructure, meaning that construction may not even be possible.
Moreover, Air Products argues that even if the transmission could be constructed, all
transmission provides is “wires;” it does not provide any additional generation resource, and as
such is an inferior way to supply loads in ENO’s load pocket; 231 and
WHEREAS, Air Products explains that Advisors’ witness Mr. Movish reached a similar
conclusion.

Namely, that construction of capacity within the ENO service territory is far

superior to, and far less risky than, attempting to solve the reliability issues with transmission;232
and
WHEREAS, NOCS argues that ENO has not demonstrated a generation-related
reliability need. 233 According to NOCS, “[a]t best, ENO has only shown a transmission-related
reliability need.” 234 NOCS asserts that ENO failed to show that building generating capacity is
the most reasonable and cost-effective method of addressing the transmission reliability need.235

230

Air Products Post-Hearing Brief at 10-11, citing Supplemental and Amending Direct Testimony of Charles W.
Long, Docket No. UD-16-02, at 9:2-11 (July 6, 2017) (“C. Long-2”).
231
Air Products Post-Hearing Brief at 11.
232
Air Products Post-Hearing Brief at 11-12.
233
NOCS Post-Hearing Brief at 8.
234
NOCS Post-Hearing Brief at 9.
235
NOCS Post-Hearing Brief at 9.

49

 Referencing the Advisors’ testimony that the Transmission Alternative is economically more
attractive than either the CT Alternative or the RICE Alternative (yet also noting that the
Advisors do not recommend the Transmission Alternative due to the uncertainty surrounding the
costs and timing of the Transmission Alternative), NOCS also asserts that the Advisors recognize
that ENO does not face a generation reliability problem but rather a transmission reliability
problem; 236 and NOCS relies on the testimony of Air Products witness Dauphinais to support its
assertion that ENO faces a transmission reliability problem and that the Transmission Alternative
is the most cost-effective means of solving that problem; and
WHEREAS, NOCS says that it “agrees with the Council’s Advisors that the ‘Do
Nothing Option’ is not sustainable;” 237 and
WHEREAS, NOCS argues that instead of the generation proposed in the instant docket,
ENO should have acquired, through a power purchase agreement (“PPA”), a portion (roughly 20%
of the capacity) of the St. Charles Power Station, a new CCGT to be constructed by ELL. NOCS
asserts that the unit costs of the RICE and CT Alternatives far exceed the unit cost of the St.
Charles Power Station. 238 According to NOCS, ENO’s disregard of the St. Charles Power
Station as a potential resource option undermines any assertion that ENO faces a reliability need,
or, if it does have a reliability need, that the NOPS project is the lowest reasonable cost solution
to meet that need. Nevertheless, NOCS admits that the record does not contain an analysis of
whether a PPA with ELL for 20% of the St. Charles Power Station’s capacity could have
provided sufficient reliability benefits to fully address ENO’s needs; 239 and

236

NOCS Post-Hearing Brief at 9-10.
NOCS Post-Hearing Brief at 10-11.
238
NOCS Post-Hearing Brief at 11-12. According to NOCS, the RICE Alternative is estimated to cost $1,640/kW,
and the CT Alternative is estimated to cost $1,026/kW, as compared to the $886/kW price tag of the St. Charles
Power Station CCGT. Id. at 12.
239
NOCS Post-Hearing Brief at 12.
237

50

 WHEREAS, NOCS acknowledges, that “the Council may find that there is sufficient
value in the ancillary benefits that may accrue from constructing generating capacity within the
City – which currently lacks any generation – to justify adding generating capacity.” 240 In that
regard, NOCS acknowledges that should the Council decide that new generating capacity inside
the City would serve the public convenience and necessity, is in the public interest, and is
prudent, it should conditionally approve the RICE Alternative, and not the CT Alternative; 241
and
WHEREAS, the Joint Intervenors take issue with ENO’s and the Advisors’ assertions
that the New Orleans transmission system is currently unreliable and at unacceptable risk of
NERC violations and cascading outages. The Joint Intervenors also criticize the assertion that
the lack of local generation in the DSG load pocket leaves the Company at risk from stormrelated outages, and leaves the city without a source of dynamic reactive power for voltage
control. According to the Joint Intervenors, the consequences of those reliability risks are
overstated and unfounded because (1) ENO admits that it does not have any specific resource
adequacy or transmission security need for a new gas generation unit, if it “develops a plan to
reinforce five transmission lines at a cost of approximately $57 million,” or if “the Company
meets NERC transmission standards with alternative reinforcements that it has, thus far, failed to
evaluate,” 242 (2) ENO has failed to seriously evaluate any transmission reliability or reactive
power alternatives, there have been no cascading outage events since the Company’s
deactivation of Michoud, and the fact that ENO’s preferred alternative – the 226 MW CT –
cannot provide black-start support, and will not provide any reliability benefits for at least three
years, and (3) ENO failed to provide information necessary – and, in some instances, specifically
240

NOCS Post-Hearing Brief at 14.
NOCS Post-Hearing Brief at 3, 14.
242
Joint Intervenors’ Post-Hearing Brief at 24.
241

51

 requested by the Council – to make an informed decision about the reliability need for any gas
generation; 243 and
WHEREAS, Joint Intervenors argue that ENO does not have any “specific reliability
need for a new gas plant,” 244 as long as the Company develops a contingency plan that includes
modest transmission improvements. According to Joint Intervenors, there are two categories of
reliability requirements: (1) resource adequacy, and (2) transmission security needs. According
to Joint Intervenors, ENO acknowledges that gas-fired generation is not necessary to address
either need. They opine that as long as the transmission improvements are made, resource
adequacy needs can be met by resources located within and outside of the DSG load pocket,
without construction of NOPS, by relying on MISO’s Zone 9 capacity or Ninemile Station which
can provide reactive power. The Joint Intervenors also argue that additional dynamic reactive
supply can be had through the installation of Static Var Compensation (“SVC”) or synchronous
condensing devices; 245 and
WHEREAS, Joint Intervenors argue that there is no specific requirement to install gasfired capacity to address the potential NERC P6 contingencies; no such events have occurred
since the deactivation of Michoud, and the Company has not quantified the risk of any such
contingency. Further Joint Intervenors state that “despite the apparent risks of a NERC P6
contingency, the Company never warned the Council or the Advisors of any such risk prior to
filing this docket;” 246 and
WHEREAS, Joint Intervenors argue that the Company’s own study shows that it can
address transmission security reliability issues by improving five transmission lines at a cost of

243

Joint Intervenors’ Post-Hearing Brief at 24.
Joint Intervenors’ Post-Hearing Brief at 25.
245
Joint Intervenors’ Post-Hearing Brief at 25.
246
Joint Intervenors’ Post-Hearing Brief at 26.
244

52

 approximately $57 million, or through other alternative reinforcements. In this regard, Joint
Intervenors note that during its evaluation of the Attachment Y for the retirement of the Michoud
units, MISO concluded that generation is not required at Michoud to maintain reliability if the
transmission improvements in the MISO Transmission Expansion Plan (“MTEP”) are
implemented. According to Joint Intervenors, “ENO admits the system will be NERC compliant
with transmission upgrades,” 247 and claims that the Company does not dispute that those
upgrades can be constructed. Joint Intervenors also claim that there is no requirement for ENO
to have local generation to provide black-start services, or in aid of restoration during extreme
storm events; 248 and
WHEREAS, Joint Intervenors argue that ENO’s and the Advisors’ dire reliability
concerns are belied by the Company’s failure to seriously evaluate any transmission reliability or
generation alternatives since the Michoud units were deactivated. Similarly the Joint Intervenors
assert ENO’s preferred alternative – the 226 MW CT – cannot provide black-start support, and
will not provide any reliability benefits for at least three years while it is being constructed. Joint
Intervenors claim that the reliability risks could be effectively mitigated with as few as 70 MW
of generation, meeting the Council’s 2% DSM Goal and transmission improvements in 2027;249
and
WHEREAS, Joint Intervenors argue that the Company has failed (or refused) to provide
the Council or the public with information necessary and, in some instances, specifically
requested by the Council – —to make an informed decision about the need for gas generation.
This failure directly contravenes the Council’s admonishment in the show cause order that the

247

Joint Intervenors’ Post-Hearing Brief at 27.
Joint Intervenors’ Post-Hearing Brief at 27.
249
Joint Intervenors’ Post-Hearing Brief at 28-29.
248

53

 CT decision “demands the maximum scrutiny possible in an open and transparent process.” 250 It
is well-established that a utility “does not meet its burden of proof” of demonstrating that a
proposed generation investment is necessary to serve the public interest “by mere speculation,
guesswork, hopes or aspirations.” 251 Instead, “a present need must be established” as part of a
“reasoned investigation of all relevant factors and alternatives” as they existed at the time the
decision; 252 and
WHEREAS, Joint Intervenors argue that ENO has failed to meet its burden of proof by
its failure to provide the Council with information necessary to determine whether new gas-fired
generation is necessary to maintain system reliability. Moreover, the Joint Intervenors assert that
the Company’s assertions about system reliability, and in particular, the ability of transmission
reinforcements and alternatives to meet any reliability needs, are premised on speculation and
guesswork. Joint Intervenors argue that the Council should disregard ENO’s claims that the
transmission upgrades will take too long, or are too difficult to implement as they are conclusory
assertions because ENO admits that it did not conduct any assessment of cost, feasibility, or the
time necessary to make those upgrades; 253 and
WHEREAS, Joint Intervenors further argue that ENO’s claims of potential catastrophe
are not persuasive because ENO did not evaluate the Council’s existing energy efficiency
programs’ reductions to peak load requirements that would reduce the risk of reliability
violations by lowering system stress. 254 Similarly, Joint Intervenors note that ENO admits that it
did not evaluate load shedding or curtailment of additional industrial load to mitigate

250

Joint Intervenors’ Post-Hearing Brief at 30, citing Resolution No. R-16-263 at 7.
Joint Intervenors’ Post-Hearing Brief at 30, citing In the Matter of the Application of KCP&L Greater Missouri
Operations Co. v. Missouri Pub. Serv. Comm’n, 515 S.W. 3d 754, 760 (W.D. Mo. App. Ct. 2017).
252
Joint Intervenors’ Post-Hearing Brief at 30, citing In the Matter of the Application of KCP&L Greater Missouri
Operations Co. v. Missouri Pub. Serv. Comm’n, 515 S.W. 3d at 760.
253
Joint Intervenors’ Post-Hearing Brief at 29-33.
254
Joint Intervenors’ Post-Hearing Brief at 32.
251

54

 transmission constraints during peak loading hours or whether additional solar generation,
battery storage, DSM, reactive power support, or even smaller generating units could more
cheaply and effectively mitigate any potential reliability concerns. 255

According to Joint

Intervenors this is a critical shortcoming because solar and batteries together can provide both
dispatchable real power and reactive power support. In this regard, Joint Intervenors claim that
ENO rejected those options because of ENO’s belief that there is insufficient space available in
New Orleans East to install sufficient solar capacity without evaluating whether there was
additional space available on commercial rooftops, or elsewhere, that could be used to
interconnect solar capacity to Michoud; 256 and
WHEREAS, Joint Intervenors argue that ENO has failed to (a) provide reliable, leastcost service to the residents of New Orleans, (b) properly plan for the deactivation of the units at
Michoud, (c) properly analyze the needs of the system, and (d) fully evaluate alternatives to its
preferred proposed generation. According to Joint Intervenors, ENO failed to use good business
judgment or act in a prudent manner and should not be rewarded for its failure to implement a
plan to correct any reliability concerns in a timely manner; 257 and
WHEREAS, Joint Intervenors argue that ENO’s own analyses show that any long-term
reliability risks can be mitigated more efficiently and effectively with a combination of energy
efficiency measures, solar generation, and limited transmission upgrades.

Similarly, Joint

Intervenors assert that the “No NOPS” option – i.e., the transmission upgrade only option –
would mitigate any transmission reliability need for New Orleans at a fraction of the cost of a
new peaking generation unit in East New Orleans. Further, Joint Intervenors assert that the
NOPS options fail to provide any near-term reliability benefits and carry their own set of risks.
255

Joint Intervenors’ Post-Hearing Brief at 33.
Joint Intervenors’ Post-Hearing Brief at 32.
257
Joint Intervenors’ Post-Hearing Brief at 33 -37.
256

55

 Additionally, Joint Intervenors state that the Council should direct ENO to provide the
information necessary to fully consider a transmission alternative, along with DSM, solar and/or
batteries; 258 and
WHEREAS, Joint Intervenors opine that any long-term reliability risks can be mitigated
more cheaply and effectively with a combination of energy efficiency measures, solar generation,
or limited transmission upgrades. According to Joint Intervenors, ENO admits that making
transmission reinforcements to just five transmission line segments would mitigate all the
reliability-based system constraints over the next 10 years without building new generation at a
fraction of the cost of a new peaking generation unit in New Orleans East. Joint Intervenors state
that these transmission upgrades are estimated to cost at the highest estimate, $57.3 million,
which compares favorably to the cost of the CT Alternative at $232 million, or the cost of the
RICE Alternative at $210 million. Further, Joint Intervenors note that the “No NOPS – Solar”
scenario is virtually identical to the RICE Alternative in terms of mitigating reliability risks at a
cost that is less expensive than either of ENO’s proposed NOPS alternatives under almost every
scenario. Moreover, Joint Intervenors assert that as a result of already “planned transmission
upgrades that are expected to be in-service by 2020” under MISO’s MTEP transmission planning,
both the “No NOPS – Solar Plus DSM” and RICE Alternatives are equally “effective in
preventing cascading outages in the New Orleans area” until 2027, when both options require
identical upgrades to the same two 230 kV transmission lines; 259 and
WHEREAS, with regard to ENO and Advisor criticisms that (1) the “No NOPS”
alternatives are infeasible because the Transmission Alternative is too difficult, too expensive,
and too time consuming to mitigate urgent reliability risks, and (2) it is extremely unlikely that

258
259

Joint Intervenors’ Post-Hearing Brief at 37-38.
Joint Intervenors’ Post-Hearing Brief at 41-42.

56

 the Company could obtain sufficient land in close proximity to Michoud to install 200 MW or
even 100 MW of solar capacity or achieve the Council’s 2% DSM Goal, the Joint Intervenors
assert that these criticisms are unfounded, and that the Council should direct ENO to provide the
information necessary to fully consider those options in lieu approving either NOPS
Alternative; 260 and
WHEREAS, Joint Intervenors opine that ENO’s and the Advisors’ criticisms and
arguments are unsupported by the record. Specifically, Joint Intervenors state that ENO admits
that it can install the required transmission upgrades by “mid-2021,” in sufficient time to
mitigate the reliability risks identified in the load flow modeling. Moreover, Joint Intervenors
note that ENO has reported “robust” proposals to build up to 325 MW of solar capacity and that
the Council has projected that at ENO’s current rate of energy efficiency savings, the Company
will meet the Council’s 2% DSM Goal by 2024; 261 and
WHEREAS, Joint Intervenors argue that there is no basis for the Council to approve
either of the “No NOPS” alternatives because of ENO’s failure to perform the level of detailed
analysis that Joint Intervenors argue is necessary for the Council’s consideration. Specifically,
Joint Intervenors state that ENO did not (a) conduct a detailed evaluation of transmission
alternatives, (b) perform any of the detailed design and scoping work necessary to provide the
timetable required to construct any of the transmission reinforcements purportedly needed to
maintain reliability, or (c) conduct any assessment of cost or the time necessary to make those
upgrades. Further, Joint Intervenors complain that ENO has not evaluated (1) the Council’s
existing energy efficiency programs, (2) other DSM opportunities or (3) the availability of
260

Joint Intervenors’ Post-Hearing Brief at 43-45.
Joint Intervenors’ Post-Hearing Brief at 44, citing City of New Orleans, Climate Action for a Resilient New
Orleans, at 30, https://www.nola.gov/nola/media/Climate-Action/Climate-Action-for-a-Resilient-New-Orleans.pdf.
The Council notes that upon review of the cited reference -“a goal we are on track to meet in 2024” are the
Council’s but rather, we presume, the author of the document.

261

57

 additional solar generation options, which could arguably reduce peak load requirements the risk
of reliability ; 262 and
WHEREAS, Joint Intervenors argue that both of the proposed NOPS units present
reliability risks.

First, neither of the proposed generation units can be placed in service

immediately, 2020 at the earliest for the RICE unit, and 2021 for the CT unit. Second, Joint
Intervenors claim a hurricane strong enough to produce major damage to the transmission system
also poses the threat of significant damage to any generating units. Moreover, Joint Intervenors
note that “[g]iven the Michoud location’s vulnerability to coastal flooding, ENO’s proposal to
address reliability concerns with a single large CT, especially one sited in an area subject to
routine hurricane events, flooding, and subsidence, only places the area at further risk of
reliability constraints;” 263 and
WHEREAS, Joint Intervenors argue that there are alternative means to effectively and
quickly mitigate any transmission reliability concerns while longer-term solutions are put into
place, including: (1) continued reliance on resources both within and outside of the DSG load
pocket (and outside of New Orleans); (2) ongoing MISO South transmission reinforcement
projects; (3) additional off-the-shelf transmission reinforcements; (4) installation of additional
reactive power; (5) the evaluation and implementation of a combination of options, such as
additional steps to reduce peak load, solar photovoltaic (“PV”), and dispatchable battery storage
options. Indeed, several of these options already are contributing to reduce system peak loads on
ENO’s system, thereby directly mitigating any reliability risk; 264 and
WHEREAS, Joint Intervenors argue that there are ample generation resources both
within and outside of the DSG load pocket that will continue to ensure resource adequacy until
262

Joint Intervenors’ Post-Hearing Brief at 43-44.
Joint Intervenors’ Post-Hearing Brief at 44-45.
264
Joint Intervenors’ Post-Hearing Brief at 46.
263

58

 alternative resources are fully deployed. Joint Intervenors specifically note that (a) with the
continued operation of the three units at Ninemile Station directly across the river from New
Orleans, (b) MISO Zone 9 capacity obligations, which do not include any reliability requirement
for New Orleans generation, and (c) there is ample capacity to maintain resource adequacy in the
New Orleans area because at the most recent MISO PRA, capacity cleared at extremely low
prices. Moreover, Joint Intervenors state that ENO has the authority to ensure that Ninemile
Station, Little Gypsy, and Waterford remain operational; 265 and
WHEREAS, Joint Intervenors argue that ENO’s own analyses demonstrate that ongoing
MISO transmission projects and decreasing load are already working to improve transmission
security on the ENO system and will provide ENO with additional time and flexibility to
evaluate and implement any additional transmission reinforcements that may be necessary.
Specifically, Joint Intervenors point to nine ongoing transmission improvement projects that are
contributing to improved transmission reliability in the DSG load pocket. Joint Intervenors note
that eight of those nine projects are in or around New Orleans. Joint Intervenors further note that
these transmission upgrades are separate from the transmission upgrades ENO witness Charles
Long concludes would be necessary under the “No NOPS” alternative.

Further, Joint

Intervenors state that as a result of these ongoing MISO transmission projects, ENO’s updated
July 2017 power flow analyses reflect a reduction in the number of transmission reinforcements
required— from eight lines in 2016 to five lines in July 2017. Moreover, Joint Intervenors assert
that ENO’s November 2017 revised load forecast showed that only four transmission projects
were now required to mitigate any transmission reliability risk; 266 and

265
266

Joint Intervenors’ Post-Hearing Brief at 46-47.
Joint Intervenors’ Post-Hearing Brief at 47-48.

59

 WHEREAS, Joint Intervenors state that ENO admits that the MISO transmission
projects that are coming online improve reliability, and take issue with the Company’s
characterization of those transmission projects as the “smallest” factors in the improved
modeling results. 267 Joint Intervenors contend that Mr. Long’s own load flow analysis shows
improved reliability as the result of those MISO transmission projects.

Specifically, Joint

Intervenors argue that ENO’s load forecasts for 2019 and 2022 are virtually identical and that
any improvement in reliability is not attributable to changes in load but rather is due to MISO
transmission improvements coming online in 2020 and ENO’s corrections to the DSM forecast.
Moreover, Joint Intervenors argue that because these two variables result in a nearly 20%
decrease in transmission overloading from 2019 to 2022, under the “No NOPS” scenario, this
indicates that ongoing MISO transmission upgrades are not only materially improving
transmission reliability in New Orleans, and thereby decreasing the likelihood of cascading
outages, but that those transmission improvements will provide ENO with additional flexibility
and time to schedule any outages that may be required to address remaining transmission risks or
explore additional alternatives, like increased DSM, that can mitigate any remaining reliability
risk; 268 and
WHEREAS, Joint Intervenors

argue that

there are alternative transmission

reinforcements, which ENO failed to consider, that are readily available and can be implemented
within months without requiring new rights of way or extended outages to supplement or repair
transmission lines. According to Joint Intervenors, ENO admitted that a second transformer
would “allow more flow between the 230 [kV] and 115 [kV] systems and provide helpful

267
268

Joint Intervenor’s Post-Hearing Brief at 49.
Joint Intervenors’ Post-Hearing Brief at 49-50.

60

 transmission reliability benefits.” 269

Similarly, Joint Intervenors argue that ENO failed to

provide any support for its assertion that there are significant constructability issues with
upgrading transmission lines. In this regard, Joint Intervenors assert that Mr. Long’s view that a
particular upgrade would be “extraordinarily” difficult to install is unfounded because ENO
owns the substations and thus any obstacles to obtaining rights of way or upgrading miles of
transmission lines do not exist in this instance. Moreover, Joint Intervenors claim that because
ENO was able to secure the outages required to install a second transformer at the Snake Farm
substation, it would be feasible to install similar transmission reinforcements at the two
substations most susceptible to critical NERC contingencies; 270 and
WHEREAS, Joint Intervenors also argue that Static Var Compensators or synchronous
condensers that can supply significant amounts of reactive power and are considered a “valuable”
transmission asset. According to Joint Intervenors’ witness Mr. Lanzalotta, dynamic reactive
power support options like Static Var Compensation, are the preferred tool for dynamic reactive
power support in high voltage transmission grids due to its inherent capability for high-speed
response to voltage depressions, and its ability to quickly supply inductive loads, such as air
conditioning compressors, elevator drives, and industrial motors; 271 and
WHEREAS, Joint Intervenors argue that solar PV and dispatchable battery storage are
options to reduce peak load. According to Joint Intervenors, ENO can take more aggressive
steps to both reduce peak load on its system through additional DSM measures and increase
installation of local solar PV and battery options which arguably can provide improved
transmission security, help mitigate outage scheduling difficulties, provide dispatchable real

269

Joint Intervenors’ Post-Hearing Brief at 31 n.122, citing Hr’g Tr. 12/15/17, 156:3-4; 157:7-11.
Joint Intervenors’ Post-Hearing Brief at 50-52.
271
Joint Intervenors’ Post-Hearing Brief at 52-53.
270

61

 power and reactive support. 272 In this regard, Joint Intervenors argue that ENO’s November
2017 load flow analysis, which “corrected DSM assumptions” and “properly account for the 2%
DSM Goal,” 273 shows that the inclusion of additional DSM can materially reduce stress on the
system. As noted above, according to Joint Intervenors, applying just that 2% DSM correction,
ENO’s updated load flow modeling for the “No NOPS,” Transmission Alternative shows a
reduction in the number of transmission reinforcements needed, from five lines in the July 2017
analysis to four lines in the November 2017 analysis; 274 and
WHEREAS, Joint Intervenors opine that ENO’s assertion that additional DSM is
infeasible is belied by the fact that the Company did not actually conduct any analysis of
additional opportunities for DSM load reductions, including the potential for securing additional
industrial load shedding or curtailment contracts – an acceptable, NERC-compliant way to deal
with transmission reliability risks. Similarly, according to Joint Intervenors, ENO refused to
study – and fails to explain – why it cannot secure additional curtailable load. Moreover, Joint
Intervenors submit that ENO’s claims about the feasibility of reducing load through energy
efficiency are similarly unsupported and that ENO’s arguments are contradicted by ENO’s own
energy efficiency consultant, and the City of New Orleans’ determination that the Company
could actually achieve 3.3% annual energy savings; 275 and
WHEREAS, Joint Intervenors argue that ENO also admits that the installation of
additional solar resources, interconnected at Michoud, can improve system reliability but that it
failed to study whether additional solar resources, including siting solar PV on commercial
rooftops, is possible. According to Joint Intervenors, ENO’s RFP suggests that local additional

272

Joint Intervenors’ Post-Hearing Brief at 53.
Joint Intervenors’ Post-Hearing Brief at 54, citing C-Long-3 at 42:12-15.
274
Joint Intervenors’ Post-Hearing Brief at 54.
275
Joint Intervenors’ Post-Hearing Brief at 54-55.
273

62

 solar resources are, in fact, available and that ENO represented to the Council that there was
“robust” participation in the Company’s 2016 renewables RFP process, with 17 conforming
proposals representing approximately 325 MW of potential solar PV capacity; 276 and
WHEREAS, Joint Intervenors complain that although ENO criticizes the transmission
benefits of additional solar capacity because solar is “not a dispatchable resource,” it did not
evaluate the potential transmission benefits of additional solar resources coupled with battery
storage, which, according to Joint Intervenors, is a dispatchable resource.

Further, Joint

Intervenors assert that despite the Council’s explicit request that ENO evaluate battery storage
alternatives to fossil resources, the Company failed to even consider the possibility that battery
storage coupled with renewable resource could provide transmission benefits during peak load,
which generally occurs over period of hours; 277 and
WHEREAS, Joint Intervenors profess that the Advisors and ENO have absolutely no
knowledge of whether batteries could provide reliability benefits, or whether other utilities
across the country have installed solar and battery arrays to mitigate transmission reliability
issues. In contrast, Joint Intervenors note that Joint Intervenors’ witness Mr. Luckow testified
that utilities across the country are actively seeking and procuring battery storage alternatives in
lieu of other peaking resources to satisfy local capacity and reliability requirements; 278 and
WHEREAS, Joint Intervenors argue that ENO’s remaining “reliability” arguments for
NOPS are illusory. In this regard Joint Intervenors criticize ENO’s and the Advisors’ arguments
that new gas-fired generation will (1) provide the potential to power to the S&WB Carrolton
pumping plant if there is an islanding event, and (2) provide storm restoration and “black-start”
capability to assist in returning service to customers as quickly as possible after extreme storm
276

Joint Intervenors’ Post-Hearing Brief at 55-56.
Joint Intervenors’ Post-Hearing Brief at 56.
278
Joint Intervenors’ Post-Hearing Brief at 56-58.
277

63

 events or outages. According to Joint Intervenors, those arguments are speculative because
ENO’s and the Advisors’ witnesses have not supplied any evidence demonstrating that these
purported benefits will be realized; 279 and
WHEREAS, Joint Intervenors note that Advisors’ witness Phillip Movish testified that
gas-fired generation located at Michoud could “potentially” provide power to the S&WB’s
Carrolton pumping plant in the event that the S&WB’s generating capacity is impaired. Joint
Intervenors argue that there is no evidence that the S&WB has even asked ENO to provide
backup power for Carrolton with a new power plant. Joint Intervenors also argue that even if
ENO does need to provide power to S&WB, ENO has failed to explain why the Company’s
Ninemile power plant, which is directly across the river from Carrolton, cannot provide
generation support for the facility. Also, Joint Intervenors assert that ENO did not evaluate
whether any less expensive alternative, such as installing a substation at Carrolton, could serve
S&WB load more cheaply and reliably than the gas plant. Joint Intervenors also contend that,
because S&WB recently installed its own quick-start emergency generator, it is not clear that the
facility even has a need for black-start capability from ENO. Moreover, Joint Intervenors note
that the purported benefit of serving the SW&B in emergencies does not apply to the CT
Alternative as it lacks black-start capability; 280 and
WHEREAS, Joint Intervenors argue that ENO’s assertion that a local gas generating unit
can help provide electric service restoration after events such as hurricanes is speculative and
unsupported because ENO never conducted any modeling to determine how a gas plant, or any
alternatives to a gas plant, would support the City’s recovery from a major storm or would even
be available during a hurricane event. According to Joint Intervenors, ENO ignores the fact that

279
280

Joint Intervenors’ Post-Hearing Brief at 58.
Joint Intervenors’ Post-Hearing Brief at 58-60.

64

 a hurricane strong enough to produce major damage to the transmission system also poses a
significant threat to any local generating units. Moreover, Joint Intervenors assert that Hurricane
Gustav provides another example undermining the Company’s assertion that generation is
needed at Michoud to deal with storm impacts. According to Joint Intervenors, Hurricane
Gustav caused extensive damage to the distribution system, resulting in the islanding of the DSG
area and requiring ENO to take the Michoud units offline. Joint Intervenors state that despite the
lack of any generation at Michoud, there was still sufficient generation, primarily from Ninemile
Station, to power the DSG load pocket; 281 and
WHEREAS, Joint Intervenors assert that even if the proposed NOPS options could
operate on their own following a storm, they could only supply enough power to serve a small
part of ENO’s normal load. Moreover, Joint Intervenors argue that the ability of a gas-burning
generation unit to provide power to the City after a storm necessarily depends on the availability
of natural gas supply. In contrast, according to Joint Intervenors, a solar installation is not
subject to the availability of fuel; 282 and
WHEREAS, Joint Intervenors contend that while ENO pays lip service to the “blackstart” capability of the RICE unit, it continues to argue that the more expensive, 226 MW CT
that lacks black-start is the “best option” for ENO customers. According to Joint Intervenors, if
the Company truly needed improved black-start capability, it would not continue to seek
approval of the larger CT option; 283 and
WHEREAS, Joint Intervenors argue that if ENO relies on existing generation to ensure
service in the face of widespread storm outages and if it performs further upgrades to its

281

Joint Intervenors’ Post-Hearing Brief at 61.
Joint Intervenors’ Post-Hearing Brief at 62.
283
Joint Intervenors’ Post-Hearing Brief at 62.
282

65

 transmission lines, rather than deferring those upgrades to build a gas plant, it can also improve
the system’s ability to respond to outages and storm events; 284 and
WHEREAS, the Advisors argue that the record is clear that ENO has a current and
critical need for generation resources in Orleans Parish to assure reliability and avoid an
unacceptable risk of cascading outages of long duration.

That need exists today and will

continue to exist until generation is constructed in New Orleans. Further, based on the evidence
presented, all parties appear to be in agreement that ENO currently faces reliability risks since
the deactivation of Michoud in 2016; 285 and
WHEREAS, the Advisors state that since the deactivation of Michoud, all of the units
ENO relies on for reliability are located outside Orleans Parish, and many of the existing units in
the region are old and may soon be retired. The City is entirely dependent upon transmission
lines to meet reliability requirements and demand; 286 and
WHEREAS, the Advisors explain that New Orleans is located in the constrained DSG
region of the power system. The DSG region is largely surrounded by water, it contains highly
concentrated electrical loads that are largely reliant on local generation to maintain reliability,
and has a limited import capability, making it a “load pocket.” 287 New Orleans is located in a
geographical and electrical peninsula bordered by water on the north, east and south. Almost all
electrical energy is imported into the City from the west, primarily through East Jefferson Parish
via the transmission grid, while a small amount of electric energy is transported through the very
limited transmission capability from the Slidell area over the open waters of Lake Pontchartrain.
The existing transmission facilities serving the City traverse a limited set of viable transmission

284

Joint Intervenors’ Post-Hearing Brief at 62-63, citing Lanzalotta-1 at 10:5-13.
Advisors’ Post-Hearing Brief at 30, 40.
286
Advisors’ Post-Hearing Brief at 30-31.
287
Advisors’ Post-Hearing Brief at 30-31.
285

66

 corridors across wetlands and generally poor soil conditions through an area heavily congested
with industrial, commercial, and residential structures; 288 and
WHEREAS, the Advisors point out that no party refuted the fact that the geography
surrounding New Orleans limits the amount of transmission facilities available to serve the City;
and
WHEREAS, the Advisors argue that without a local generation resource, the City in
general, and New Orleans East in particular, is entirely dependent on the set of existing
transmission lines situated in a relatively small geographical area, and the loss of even a portion
of these transmission facilities delivering energy from the West into the City would likely
prevent the Company from serving its entire load; 289 and
WHEREAS, the Advisors explain that in the DSG region, the simultaneous loss of a
generation resource and a transmission element often results in voltage and thermal constraints
which cannot be mitigated without the commitment of another local unit, particularly since many
of the generators in the region have long start-up times. Because of the unique configuration and
system constraints, all DSG generating units, including Michoud when it was operational, are
committed as “Voltage and Local Reliability” resources to ensure that enough capacity exists in
the region to maintain reliability; 290 and
WHEREAS, the Advisors state that the record shows that the deactivation of Michoud
has left ENO with a critical need for generation in order to keep the system from collapsing in
the event of certain contingencies, and without construction of incremental dispatchable local
generation (i.e., NOPS), the City and DSG region will experience a degradation in system
reliability. New Orleans faces a risk of cascading outages with loss of electric load served from
288

Advisors’ Post-Hearing Brief at 31-32.
Advisors’ Post-Hearing Brief at 31-32.
290
Advisors’ Post-Hearing Brief at 32, 40.
289

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 most of ENO’s substations, leaving 49,000 ENO customers without power for extended periods
of time, particularly in New Orleans East; 291 and
WHEREAS, the Advisors state that the record demonstrates that ENO is at risk of being
in violation of the standards set by NERC, and is presently at risk for two NERC contingencies
in particular. Of greatest concern, ENO is at risk of a “P6” contingency, which involves loss of
multiple transmission facilities; 292 and
WHEREAS, ENO’s current solution to address the contingencies is load shedding, i.e.,
deliberately curtailing service to a portion of its customers in order to prevent the collapse of the
entire system; 293 and
WHEREAS, the Advisors say that if NOPS is not approved, ENO will have to make
extensive transmission upgrades in order to maintain system reliability and remain in compliance
with NERC standards, but that there are serious constructability issues associated with any such
construction of transmission. 294

It would take longer to plan and implement transmission

upgrades than to construct NOPS on a site that ENO already owns; there is a possibility that
ENO would not be able to get the outages it would need to make the upgrades; and there is a
serious risk of a P6 event occurring while the upgrade are being done because of the constraints
on the system; 295 and
WHEREAS, the Advisors remind the Council that at a recent UCTTC meeting,
representatives from MISO reported on ongoing operational challenges of operating the grid in
the DSG load pocket, emphasized the importance of having local generation in the City. MISO

291

Advisors’ Post-Hearing Brief at 32-33.
Advisors’ Post-Hearing Brief at 34-35, 40-41.
293
Advisors’ Post-Hearing Brief at 35.
294
Advisors’ Post-Hearing Brief at 35-37.
295
Advisors’ Post-Hearing Brief at 36.
292

68

 has confirmed ENO’s own analyses of the long-term reliability risks it currently faces, including
the possibility of long-duration cascading outages; 296 and
WHEREAS, the Advisors also point out that DSM and solar do not resolve the reliability
issue because at times these resources provide zero capacity, and so cannot be relied on for
purposes of meeting NERC criteria; 297 and
WHEREAS, the Advisors disagree with Air Products witness Mr. Dauphinais, who,
without any support, evidence or substantive argument, asserts that ENO has not reasonably
demonstrated there is a local thermal, voltage, reactive power or resource adequacy need for the
CT Alternative. This contention, the Advisors state, is contrary to other witnesses, including Air
Products witness Mr. Brubaker, who recognized a long-term capacity need and the present risk
of cascading outages; 298 and Joint Intervenors’ witness Mr. Luckow, who, though he argues that
the reliability need is overstated, nonetheless acknowledges that absent transmission
reinforcements in the DSG load pocket area, there would be violations of transmission
security; 299 and
WHEREAS, the Advisors point out that while Joint Intervenors’ witness Mr. Fagan
argued that transmission reliability could be achieved by reinforcing existing transmission
facilities, 300 he admitted on cross-examination that when he prepared his testimony, he had not
done any studies to determine the feasibility of outage scheduling for transmission lines into the
ENO service area for the next 10 years, and that he has never planned or operated transmission in
MISO South, so his speculation as to how easily transmission upgrades can be accomplished

296

Advisors’ Post-Hearing Brief at 35.
Advisors’ Post-Hearing Brief at 37.
298
Advisors’ Post-Hearing Brief at 37.
299
Advisors’ Post-Hearing Brief at 37-38.
300
Advisors’ Post-Hearing Brief at 38-39.
297

69

 appears to lack any foundation.

301

He also admitted upon cross-examination that in

recommending a transmission-only option with reliance on the MISO capacity market to meet
capacity needs, he was not familiar with and did not address or do any analysis of narrow
constrained areas within MISO South; 302 and
WHEREAS, the Advisors note that Joint Intervenors’ witness Dr. Stanton, similarly
lacks experience in transmission planning or utility operations, 303 and while she advocated
focusing resources on improving ENO’s distribution system, she admitted that she had not
conducted any analysis of ENO’s distribution system and agreed that investment in the
distribution system is not a viable alternative to addressing ENO’s capacity needs; 304 and
WHEREAS, after evaluating all of the evidence in the record, the Council finds that
there is no disagreement that since the deactivation of Michoud, ENO faces a serious reliability
risk. The parties disagree over the appropriate method of addressing this risk, but no party has
provided credible evidence that refutes the existence of the risk, or that calls into question the
severity of the problem; and
WHEREAS, since the deactivation of Michoud, ENO is entirely dependent upon
transmission lines to meet reliability requirements and demand, and all of the generating units
ENO relies on for reliability are located outside Orleans Parish. Further, the geography of New
Orleans and the surrounding DSG region is such that the reliability risks to ENO’s system are
exacerbated. New Orleans is a peninsula, bordered by water on the north, east and south.
Almost all electrical energy is imported into the City from the West, primarily through East
Jefferson Parish via the transmission grid, while a small amount of electric energy is transported

301

Advisors’ Post-Hearing Brief at 39, citing Hr’g Tr. 12/19/17, 32:3-15.
Advisors’ Post-Hearing Brief at 39, citing Hr’g Tr. 12/19/17, 31:10-19.
303
Advisors’ Post-Hearing Brief at 39.
304
Advisors’ Post-Hearing Brief at 39-40, citing Stanton-1 at 44:8-48-21 and Hr’g Tr. 12/21/17, 27:4-11.
302

70

 through the very limited transmission capability from the Slidell area over the open waters. The
DSG region contains highly concentrated electrical loads that are largely reliant on local
generation to maintain reliability. Further, the region has limited import capability; and
WHEREAS, the Council agrees with ENO and the Advisors that without a local
generation resource, the City is entirely dependent on the set of existing transmission lines
situated in a relatively small geographical area. The loss of even a portion of these transmission
facilities delivering energy from the West into the City would likely prevent the Company from
serving its entire load. The Council finds that it is urgent to address ENO’s reliability issue to
prevent degradation in system reliability, leading to the risk of cascading outages that will leave
49,000 ENO customers without power for extended periods of time, particularly in New Orleans
East; and
WHEREAS, the record demonstrates that without a corrective action plan, as ENO has
proposed to develop NOPS, ENO would be in violation of the standards set by NERC, and is
presently at risk for two NERC contingencies in particular. Of greatest concern, ENO is at risk
of a “P6” contingency, which involves loss of multiple transmission facilities resulting in
cascading outages; 305 and
WHEREAS, ENO’s current solution to address the contingencies, i.e., load shedding, is
not a viable long-term solution to the reliability issue, although the Council recognizes that in the
short term, ENO may at times be forced to curtail service to a portion of its customers in order to
prevent the collapse of the entire system; 306 and

305
306

Advisors’ Post-Hearing Brief at 34-35, 40-41.
Advisors’ Post-Hearing Brief at 35.

71

 WHEREAS, the record demonstrates that without the addition of local generation to
ENO’s system, ENO will have to make extensive transmission upgrades in order to maintain
system reliability and remain in compliance with NERC standards; and
WHEREAS, no party has rebutted ENO’s contention that there are significant, and
possibly insurmountable challenges associated with any transmission construction, whether it
involves upgrades to existing lines or construction of new facilities. No party has refuted ENO’s
claim that it would take longer to plan and implement transmission upgrades than to construct
NOPS on a site that ENO already owns. No party has refuted that there is a real likelihood that
ENO would not be able to get the outages it would need to make any upgrades, and even if it did,
the upgrades could take many years to complete. No party has refuted ENO’s assertion that
there is a serious risk of a P6 event occurring while any upgrades are being done because of the
constraints on the system.

Opponents of NOPS who support a transmission-only solution

acknowledged the challenges ENO would face if it were to attempt to construct new facilities,
particularly challenges in obtaining rights of way; and
WHEREAS, MISO has validated ENO’s analyses of the long-term reliability risks it
currently faces, including the possibility of long-duration cascading outages, and has emphasized
the importance of having local generation in New Orleans; and
WHEREAS, the Council notes that witnesses for opponents of NOPS have not done any
studies that would support their alternative proposals or assertions that ENO has viable options
other than NOPS to address the reliability issues. These witnesses have not conducted studies to
determine the feasibility of outage scheduling for transmission lines into the ENO service area
for the next 10 years; they have not planned or operated transmission in MISO South; they have

72

 not conducted any analysis of ENO’s system specifically to support their proposed alternatives.
In some cases, they had never been to New Orleans prior to this case; 307 and
WHEREAS, the Council strongly supports the addition of DSM, solar or other
renewable resources, and increased efficiency measures to ENO’s system. However, the Council
recognizes that none of these solutions would fully resolve the critical reliability issue ENO and
the City currently face. These resources cannot be counted on for reliability because at times
they provide zero capacity. Further, the record indicates that these measures would not be
sufficient to resolve the reliability problem; and
WHEREAS, in sum, the Council finds that ENO has conclusively demonstrated a critical
and urgent reliability need; and
II.

Whether either of ENO’s choices of technology(ies) is in the public interest

WHEREAS, with respect to the two alternatives ENO has presented to the Council for
consideration, the CT Alternative and the RICE Alternative, ENO argues that both alternatives
are in the public interest; 308 and
WHEREAS, the Joint Intervenors argue that neither alternative is in the public
interest; 309 and
WHEREAS, NOCS argues that the CT Alternative is not in the public interest and that
the RICE Alternative shares many of the same infirmities, but if the Council chooses to authorize
one of the two alternatives, it should be the RICE Alternative; and
WHEREAS, Air Products and the Advisors argue that the RICE Alternative is in the
public interest, but the CT Alternative is not.

307

Air Products also argues that while the

Advisors’ Post-Hearing Brief at 38-40, citing Hr’g Tr. 12/19/17, 31:10-32:15; Hr’g Tr. 12/21/17, 11:19-22 and
27:4-11.
308
ENO Post-Hearing Brief at 85-92.
309
Joint Intervenors’ Post-Hearing Brief at 63-92.

73

 infrastructure for the entire RICE Alternative should be constructed, only five of the seven RICE
units should be built at this time; and
A.

Whether ENO’s selection of a CT unit is in the public interest

WHEREAS, ENO argues that it has shown that the selection of the CT Alternative is in
the public interest. 310

ENO states that its NOPS Project Team evaluated several different

technologies, and the proposed CT unit was determined to be the better economic option for
ENO’s customers, considering the total relevant supply cost method, which included comparing
fixed costs, variable production cost, MISO capacity purchase costs, and transmission. 311 ENO
argues that the proposed CT unit supports the Company’s long-term planning objectives and is
consistent with its supply role needs; 312 and
WHEREAS, ENO argues that the CT Alternative, which consists of one Mitsubishi
Hitachi Power Systems America 501 GAC CT unit that would provide approximately 226 MW
(nominal) of summer generating capacity, is a turbine that other Entergy Operating Companies
have purchased for the St. Charles, Lake Charles, and Montgomery County Power Stations. 313
ENO asserts that other Entergy Operating Companies have had positive prior experiences with
Mitsubishi as a supplier of gas and steam turbines and received superior service; 314 and
WHEREAS, ENO argues that the CT Alternative fulfills both the capacity and reliability
needs of ENO for the Company’s full planning horizon, and that adding it will eliminate all grid
reliability issues within the current 10-year planning horizon; 315 and

310

ENO Post-Hearing Brief at 86.
ENO Post-Hearing Brief at 86.
312
ENO Post-Hearing Brief at 86.
313
ENO Post-Hearing Brief at 86.
314
ENO Post-Hearing Brief at 86.
315
ENO Post-Hearing Brief at 87, citing Cureington-6 at 7 and 11, C. Long-2 at 9-10 and 13, and Direct Testimony
and Exhibit of Philip Movish, Docket No. UD-16-02, at 43 (Nov. 20, 2017) (“Movish-1”).
311

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 WHEREAS, ENO argues that on top of addressing the capacity and reliability needs, the
CT will provide additional benefits, including: (1) avoiding costly and time-consuming
transmission upgrades; (2) providing the capability to back up renewable resources when they
are not available; (3) facilitating more load-serving capability and system restoration following
extreme weather; (4) providing more of a hedge against congestion on the transmission system
that tends to increase locational marginal pricing in the New Orleans Load Zone; (5) facilitating
planned transmission and generation maintenance outages in the load pocket and mitigating the
risk associated with unplanned outages; and (6) providing a quick-start, fast ramping resource
capable of responding to real-time operational needs of the ENO system; 316 and
WHEREAS, ENO also asserts that the CT Alternative will produce significant economic
benefits (hundreds of millions of dollars) in terms of new business sales, household earnings, and
jobs in both the state and regional economies and provides a study of the economic impact of
NOPS in support of this assertion; 317 and
WHEREAS, ENO argues that although the Company also proposed the RICE
Alternative, and it recognizes that the Council must balance several factors to choose between
the two options, the CT Alternative remains the best option for ENO’s customers. 318 ENO
argues that on a $/kW basis, the CT Alternative has a lower supply cost than the RICE
Alternative and that there are benefits that increase as the size of the generator increases, such as
larger reliability margins, a greater hedge against market and supply risks and unit retirements in
Amite South and DSG, and creating more reactive power and flexibility to take transmission
outages; 319 and

316

ENO Post-Hearing Brief at 87-88, citing Cureington-8 at 4.
Rice-3 at 15:20-16:4; Rice-1, Ex. CLR-1 at ii.
318
ENO Post-Hearing Brief at 88.
319
ENO Post-Hearing Brief at 88.
317

75

 WHEREAS, NOCS argues that, particularly in light of ENO’s inability to show a need
for 226 MW of additional generating capacity, the CT Alternative is not in the public interest.320
NOCS argues that even if ENO could show a need in the foreseeable future for 226 MW of
additional generating capacity, the question still remains of whether CT technology is the best,
most economical solution to meet such capacity need. 321 NOCS asserts that while ENO argues
there are ancillary benefits to constructing the over-sized CT Alternative, such as ostensibly
eliminating all NERC transmission reliability issues, it neglects to quantify any such ancillary
benefits or to explain the relative value of the ancillary benefits to be provided by the CT
Alternative as compared to the ancillary benefits to be provided by the RICE Alternative; 322 and
WHEREAS, NOCS argues that the choice of CT technology is not supported by ENO’s
own analyses of the optimal mix of generating resource technologies in the 2015 Final IRP,
during which the AURORA modeling selected a CCGT resource in three of the four scenarios
and a combination of solar and wind for the fourth scenario; 323 and
WHEREAS, NOCS argues that given that it was neither identified as an optimal
technology by the AURORA model, nor selected as the result of the IRP process or an RFP
process, its excessive size and cost, and its disadvantages as compared to the RICE Alternative
lead to the inescapable conclusion that ENO cannot prove the CT Alternative is in the public
interest; 324 and
WHEREAS, the Joint Intervenors argue that the CT Alternative is not in the public
interest. 325 The Joint Intervenors argue that the Council’s resolution 326 and the public interest

320

NOCS Post-Hearing Brief at 14.
NOCS Post-Hearing Brief at 14.
322
NOCS Post-Hearing Brief at 14-15.
323
NOCS Post-Hearing Brief at 15, citing Rogers-1 at 14:6-15:3.
324
NOCS Post-Hearing Brief at 15.
325
Joint Intervenors’ Post-Hearing Brief at 63.
326
Joint Intervenors’ Post-Hearing Brief at 63-64, citing Resolution No. R-17-100.
321

76

 standard require consideration of a broad range of cost, environmental, and public health
considerations. 327 The Joint Intervenors argue that ENO has not met its burden of proving that
NOPS is in the public interest of New Orleans citizens; 328 and
WHEREAS, the Joint Intervenors argue that the Company has not proven a capacity
need or a reliability need for the CT Alternative; 329 and
WHEREAS, the Joint Intervenors argue that the CT Alternative is not the least-cost
alternative and would cost ratepayers more than transmission and solar-powered solutions. 330
The Joint Intervenors argue that upgrading New Orleans’ transmission lines and installing utilityscale solar would be the economically preferred alternative. 331 They argue that ENO’s case for
the CT Alternative rests heavily on MISO capacity market prices approaching CONE, allowing
New Orleans ratepayers to offset the relatively high construction costs of the CT Alternative with
capacity sales revenues. 332

Joint Intervenors argue that ENO’s assumption of a 16,000%

increase in the MISO capacity market price by 2022 is unlikely to occur and is unreasonable.333
The Joint Intervenors argue that the monthly residential customer electric bill in the
Transmission Alternative would be approximately 75% less than in the case of the CT
Alternative; 334 and
WHEREAS, the Joint Intervenors also argue that ENO failed to adequately assess the
impacts of constructing a gas-fired plant on the environment, including increased air pollution,

327

Joint Intervenors’ Post-Hearing Brief at 63-65.
Joint Intervenors’ Post-Hearing Brief at 64.
329
Joint Intervenors’ Post-Hearing Brief at 64.
330
Joint Intervenors’ Post-Hearing Brief at 64.
331
Joint Intervenors’ Post-Hearing Brief at 65.
332
Joint Intervenors’ Post-Hearing Brief at 65.
333
Joint Intervenors’ Post-Hearing Brief at 65-66, citing Direct Testimony and Exhibits of Dr. Elizabeth Stanton,
Docket No. UD-16-02, at 21, Figure 8 (Oct. 16, 2017) (HSPM) (“Stanton-2”), Direct Testimony and Exhibits of
Robert Fagan, Docket No. UD-16-02, at 4:4-5:9 (Oct. 16, 2017) (HSPM) (“Fagan-2”), Rogers-2 at 33:7-11; 36:637:15; Cureington-8, Ex. SEC-15 at 15.
334
Joint Intervenors’ Post-Hearing Brief at 66.
328

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 subsidence, or flooding. 335 The Joint Intervenors argue that the CT Alternative would employ a
polluting technology that would place significant environmental burdens on predominately
people of color an poor communities. 336 The Joint Intervenors argue that the CT Alternative
would create racially disproportionate environmental burdens on predominately African
American and Vietnamese neighborhoods in New Orleans East and that it would release
significant amounts of air pollution near homes and schools annually. 337 The Joint Intervenors
also argue that the CT Alternative would create significant flood risks that can impact the same
surrounding neighborhoods which have yet to fully recover from the levee failure during
Hurricane Katrina; 338 and
WHEREAS, the Joint Intervenors argue that ENO’s pollution estimates for the CT
Alternative have not been confirmed by the LDEQ, and that they do not include the amounts of
sulfuric acid or the types and amounts of toxins that would be discharged as water pollution.339
The Joint Intervenors argue that the ambient air quality will worsen with the CT Alternative’s
annual releases of approximately 2,000,000 pounds of air pollution; 340 and
WHEREAS, the Joint Intervenors claim that ENO argues that the gas plant would meet
the requirements for obtaining air permits and that this would cause air quality to worsen. 341 The
Joint Intervenors argue that across Louisiana, the effects of poor air quality arise from permitted
air pollution, and that air pollution causes cancer, impairs the function of the respiratory and
cardiovascular systems and that “a regulatory standard and a guarantee of safety are not

335

Joint Intervenors’ Post-Hearing Brief at 64-65.
Joint Intervenors’ Post-Hearing Brief at 67.
337
Joint Intervenors’ Post-Hearing Brief at 67-68.
338
Joint Intervenors’ Post-Hearing Brief at 68.
339
Joint Intervenors’ Post-Hearing Brief at 70.
340
Joint Intervenors’ Post-Hearing Brief at 70.
341
Joint Intervenors’ Post-Hearing Brief at 70.
336

78

 synonymous.” 342 Joint Intervenors argue that the CT Alternative will add to pollution and cause
an increase in the risk of adverse health effects, especially for those who live within the most
affected areas of the plant; 343 and
WHEREAS, the Joint Intervenors argue that ENO’s preferred CT Alternative would
continue groundwater withdrawals, adding to the risk of subsidence. 344 The Joint Intervenors
argue that ENO’s assertion that the CT Alternative would not exacerbate subsidence in New
Orleans East ignores that the ground in New Orleans is naturally prone to subsidence and any
human-driven action that causes subsidence will intensify something that is already known to be
problematic, and that it would reduce natural recharge, and intensify natural subsidence. 345 The
Joint Intervenors’ witness Dr. Kolker testified that the subsidence issue is a serious issue that
warrants independent engineering analysis; 346 and
WHEREAS, the Joint Intervenors argue that the air pollutants from the CT Alternative
would include particulate matter (both PM 2.5 and PM 10 ), sulfur dioxide (“SO 2 ”), nitrogen oxides
(“NO X ”), carbon monoxide (“CO”), greenhouse gases (“GHGs”) and volatile organic
compounds (“VOCs”), and that for decades into the future the CT Alternative will increase the
level of harmful pollutants emitted in New Orleans East communities, and the Council should
reject the plant as contrary to the public interest in a safe and healthy New Orleans, particularly
given ENO’s failure to review other reasonable alternatives; 347 and

342

Joint Intervenors’ Post-Hearing Brief at 71, citing Supplemental Direct Testimony and Exhibits of Dr. George
Thurston, Docket No. UD-16-02, at 8 (Oct. 16, 2017) (“Thurston-2”), and Johnson v. Orleans Parish School Board,
975 So. 2d 678, 711 (La. App. 4th Cir. 2008).
343
Joint Intervenors’ Post-Hearing Brief at 71.
344
Joint Intervenors’ Post-Hearing Brief at 72-73.
345
Joint Intervenors’ Post-Hearing Brief at 73.
346
Joint Intervenors’ Post-Hearing Brief at 73.
347
Joint Intervenors’ Post-Hearing Brief at 74-75.

79

 WHEREAS, the Joint Intervenors argue that ENO’s witnesses downplayed the harmful
effect is of these pollutants, including the sharp increase in PM pollution from present levels.348
The Joint Intervenors reject the argument that it is relevant that the proposed CT Alternative will
emit fewer pollutants than the previously-existing power plant on the same site. The Joint
Intervenors also reject the argument that the net reduction in emissions will be sufficient to meet
the minimum Clean Air Act (“CAA”) permitting requirements, because “[t]he Council is not
bound by the CAA regulatory fiction that allows ENO to pretend that a significant increase in
harmful pollutants is actually a decrease in those pollutants and find that the public interest
requires a focus on the actual emissions from either gas plant;” 349 and
WHEREAS, the Joint Intervenors argue that the anticipated emissions from the CT
Alternative will not meet minimum federal standards because they will be significant enough to
trigger the EPA’s specific requirements for emissions control and analysis; 350 and
WHEREAS, the Joint Intervenors argue that the provision of the CAA that allows ENO
to avoid more stringent review by netting the emissions from the old Michoud units against the
proposed units prevents a proper evaluation of the anticipated emissions from the plant; 351 and
WHEREAS, the Joint Intervenors argue that air pollution causes decreased lung function,
more frequent asthma symptoms, increased numbers of asthma and heart attacks, more frequent
emergency department visits, additional hospital admissions, and increased numbers of deaths
and a host of additional health impacts; 352 and

348

Joint Intervenors’ Post-Hearing Brief at 75.
Joint Intervenors’ Post-Hearing Brief at 74-75.
350
Joint Intervenors’ Post-Hearing Brief at 76-77.
351
Joint Intervenors’ Post-Hearing Brief at 76.
352
Joint Intervenors’ Post-Hearing Brief at 77-79, citing Direct Testimony and Exhibits of Dr. George Thurston,
Docket No. UD-16-02, at 5-8, 10, and 25 (Jan. 6, 2017) (“Thurston-1”).
349

80

 WHEREAS, the Joint Intervenors argue that the CT Alternative is not in the public
interest because it would violate the Council’s policy on climate change. 353

The Joint

Intervenors argue that the Council has adopted a policy to reduce the City’s greenhouse gas
emissions and pursue renewable energy and energy efficiency to address the problem and that
the CT Alternative is counterproductive to those goals. 354 The Joint Intervenors also argue that
the CT Alternative would be counter to the City’s Climate Action for a Resilient New Orleans
plan and strategy to reduce its greenhouse gas emissions by 50% by 2020 and to goal of 255 MW
of solar by 2030; 355 and
WHEREAS, the Joint Intervenors argue that ENO’s proposed CT Alternative would
increase flood risks and could violate the City’s flood protection ordinance, and would conflict
with the Federal Emergency Management Agency (“FEMA”) critical infrastructure guidance; 356
and
WHEREAS, the Joint Intervenors argue that the CT Alternative is not in the public
interest because it was selected outside of the public participation and IRP Process. 357 The Joint
Intervenors argue that the fact that the Council entered into a settlement agreement with ENO in
a public FERC docket regarding the termination of the System Agreement that included the
provision requiring ENO to explore 120 MW of new-build peaking generation in New Orleans
pre-determined the positions that ENO and the Advisors would take in this proceeding and that
the record in this case provides no alternative explanation for their positions. 358 The Joint
Intervenors speculate that the Settlement Agreement holds such strong sway over this proceeding

353

Joint Intervenors’ Post-Hearing Brief at 82-84.
Joint Intervenors’ Post-Hearing Brief at 82-84.
355
Joint Intervenors’ Post-Hearing Brief at 84-86.
356
Joint Intervenors’ Post-Hearing Brief at 87-88.
357
Joint Intervenors’ Post-Hearing Brief at 88.
358
Joint Intervenors’ Post-Hearing Brief at 89-90.
354

81

 that it caused ENO and the Advisors to reject the least cost and reasonable alternatives to a gas
plant, such as renewable and efficient energy systems, DSM, and increased electric capacity of
the transmission system; 359 and
WHEREAS, the Joint Intervenors argue that the Settlement Agreement substantially
undermined the 2015 IRP process and that there is a lack of transparency in this docket regarding
the Settlement Agreement because Council Resolutions No. R-16-332, 360 R-16-506 and R-17426 do not discuss it. 361 The Joint Intervenors argue that due process has been violated because
there is no assurance that the prior Settlement Agreement does not in any way pre-determine the
outcome of the decisions leading up to the one that is anticipated from the Council in this case.362
The Joint Intervenors criticize the Council and the Advisors for failing to take action in this
docket to “resolve the due process issues that arise from the prior agreement;” 363 and
WHEREAS, the Advisors conclude that the CT Alternative is not in the public
interest. 364 While the Advisors believe it would fully address the identified reliability need over
the entire length of the planning period, they argue it would also expose customers to significant
economic risks because the capacity of the proposed CT unit far exceeds the capacity needs of
the Company for most of the planning period. 365 Further, the Advisors argue the Company’s
analysis of the economics of the CT Alternative is heavily dependent upon its forecast that MISO
capacity prices will escalate at an unprecedented rate that would allow ENO to earn significant
revenues by selling the excess capacity into the MISO market in order to offset the costs of the

359

Joint Intervenors’ Post-Hearing Brief at 90.
Resolution No. R-16-332 (Aug. 11, 2016).
361
Joint Intervenors’ Post-Hearing Brief at 91.
362
Joint Intervenors’ Post-Hearing Brief at 91-92.
363
Joint Intervenors’ Post-Hearing Brief at 92.
364
Advisors’ Post-Hearing Brief at 44.
365
Advisors’ Post-Hearing Brief at 44.
360

82

 CT Alternative to ratepayers. 366 The Advisors argue that if ENO is incorrect in its forecast that
MISO capacity prices will rise to unprecedented levels very quickly, those revenues will not
materialize and New Orleans ratepayers will have to bear significantly greater costs than ENO’s
economic analysis predicts; 367 and
WHEREAS, the Advisors explain that at the Advisors’ request, ENO witness Cureington
ran several economic analyses of the proposed alternatives for meeting the identified need. 368
The Advisors state that they also requested that ENO run three requested portfolios to model
certain assumptions advanced by the intervenors. 369 The Advisors explain that the scenarios
included portfolios with and without consideration of the Council’s 2% DSM Goal, and with or
without a variety of renewable resources. The Advisors state that the portfolios included the
Business Plan 17 Update (“BP17U”) forecast of load and commodity prices, 100 MW of solar,
continuation of Energy Smart and full deployment of ENO’s proposed AMI. 370 Sensitivities
were conducted using low and high gas prices and 60% of the MISO capacity price forecast.
The results were then incorporated into the Total Relevant Supply Cost Analysis; 371 and
WHEREAS, the Advisors state that although it was requested that ENO use AURORA’s
capacity expansion model, ENO argued that the scope of the modeling did not allow that feature
to be used. Instead, report the Advisors, ENO attempted to simulate the results of the capacity
expansion feature. 372 Accordingly, the Advisors explain, ENO conducted AURORA modeling
on four portfolios using inputs and assumptions requested by the Advisors. 373 The Advisors

366

Advisors’ Post-Hearing Brief at 44.
Advisors’ Post-Hearing Brief at 44.
368
Advisors’ Post-Hearing Brief at 44-47.
369
Advisors’ Post-Hearing Brief at 45, citing Supplemental Testimony and Exhibits of Seth E. Cureington, Docket
No. UD-16-02, at 31:18-33:11 (Nov. 18, 2016) (“Cureington-3”).
370
Advisors’ Post-Hearing Brief at 45, citing Cureington-5 at 27:1-29:8.
371
Advisors’ Post-Hearing Brief at 45, citing Cureington-5 at 27:1-29:8.
372
Advisors’ Post-Hearing Brief at 46, citing Cureington-3 at 31:18-33:11.
373
Advisors’ Post-Hearing Brief at 46, citing Cureington-3 at 31:18-33:11.
367

83

 state that the first portfolio (Case 3) evaluated the RICE, the second one (Case 3G) evaluated the
CT, 374 the third one (Case 4A) evaluated adding 100 MW solar, and the fourth one (Case 4B)
evaluated adding 300 MW of wind.375 The Advisors state that all portfolios included the BP17U
load forecast adjusted for the estimated impact of the 2% DSM Goal, the planned 100 MW of
solar, and full deployment of AMI. 376

The Advisors state that ENO also ran the same

sensitivities using low and high gas prices and the 60% MISO price forecast. 377 However, ENO
argued that the requested portfolios included an assumption of attaining the 2% DSM Goal,
which is not likely to be attainable, and would not be cost-effective, as demonstrated by the
Navigant report; 378 and
WHEREAS, in all scenarios, ENO witness Cureington concluded that the CT
Alternative was more cost-effective than the RICE Alternative, and in most scenarios, was the
most cost-effective option over-all; 379 and
WHEREAS the Advisors disagree with ENO’s economic analysis. 380 Advisors’ witness
Rogers finds that the significant reduction in projected total load requirements since the 2015
Final IRP, where a 250 MW CT was selected as part of the preferred portfolio, would strongly
suggest that 226 MW may be greater than the optimal size for the proposed peaking plant, on a
capacity need basis; 381 and
WHEREAS, Advisors’ witness Rogers explained that the primary risk in building a plant
that offers excess capacity is that it leaves customers exposed to capacity price risks, and the

374

Advisors’ Post-Hearing Brief at 46, citing Cureington-3 at 31:18-33:11.
Advisors’ Post-Hearing Brief at 46, citing Cureington-3 at 31:18-33:11.
376
Advisors’ Post-Hearing Brief at 46, citing Cureington-3 at 31:18-33:11.
377
Advisors’ Post-Hearing Brief at 46, citing Cureington-3 at 31:18-33:11.
378
Advisors’ Post-Hearing Brief at 46, citing Cureington-5 at 35:4-39:6.
379
Advisors’ Post-Hearing Brief at 46, citing Cureington-5 at 28:4-10, 29:1-8, 33:13-35:3, 44:6-15, 45:3-9.
380
Advisors’ Post-Hearing Brief at 48; Rogers-1 at 9:3-6.
381
Advisors’ Post-Hearing Brief at 48; Rogers-1 at 9:3-6.
375

84

 greater the excess amount of capacity, the greater the exposure. 382 The Advisors explain that this
means that if ENO’s MISO capacity market price forecast is wrong, the outcome for New
Orleans customers could be substantially different than what ENO sets forth. 383 The Advisors
question the assumptions underlying ENO’s MISO capacity market price forecasts and have
concerns that if ENO’s projected capacity market prices do not materialize, ENO ratepayers
could be exposed to significantly increased economic risks. 384 The Advisors explain that witness
Rogers concluded that ENO has not economically justified the CT Alternative because (i) ENO’s
economic modeling of the CT Alternative relies heavily on forecasted MISO capacity market
revenues that he finds to be questionable and (ii) when employing his illustrative MISO capacity
market prices, the CT Alternative and the RICE Alternative have roughly the same economic
attractiveness; 385 and
WHEREAS, Advisors’ witness Mr. Rogers explains, historic MISO capacity prices have
been significantly lower than the CONE that ENO uses to make its forecast of future MISO
capacity prices. 386 Mr. Rogers notes that ENO assumes as capacity supply in MISO approaches
equilibrium with demand (which ENO projects in 2022) prices will go up to approximately the
level of CONE. 387 However, Mr. Rogers notes that while ENO’s approach is generally based on
the theory of supply and demand, that theory may not be applicable to capacity prices in MISO
South. 388 Mr. Rogers notes that in several instances it has been noted before FERC that prices in
MISO’s capacity auction have been consistently too low to attract new generation investments
and that the market is not really the prime driver of entry or expansion decisions. Rather, the
382

Advisors’ Post-Hearing Brief at 48-49, Rogers-1 at 32:9-15.
Advisors’ Post-Hearing Brief at 51.
384
Advisors’ Post-Hearing Brief at 51.
385
Advisors’ Post-Hearing Brief at 48-49. Vumbaco-1 at 24:19-25:3. Rogers-1 at 30:18-31:9, 32:16-33:4, 35:10-17,
36:9-10.
386
Advisors’ Post-Hearing Brief at 52, citing Rogers-1 at 32:16-33:4.
387
Advisors’ Post-Hearing Brief at 52, citing Rogers-1 at 35:10-17.
388
Advisors’ Post-Hearing Brief at 52, citing Rogers-1 at 36:9-10.
383

85

 Advisors explain, the states located in MISO depend on state resource planning efforts by
regulated utilities to assure that their load serving entities (“LSEs”) have sufficient capacity to
meet load. 389 Thus, the Advisors conclude it is more reasonable to expect MISO capacity market
prices to generally be below CONE except for in certain, specific circumstances. 390 Building
capacity in excess of ENO’s needs in relation to the capacity market exposes ratepayers to
unnecessary risk associated with the known fixed costs of the CT Alternative as compared to
unknown market prices for the excess capacity necessary to make those resource additions
economic. 391 Mr. Rogers believes several adjustments need to be made to ENO’s economic
analyses. 392

Once he adjusted for ENO’s inconsistent transmission upgrade investment

information, used non-levelized results, and used a much lower MISO capacity price forecast, his
analysis produced a different economic ranking than did ENO’s. 393 Mr. Rogers’ analysis shows
that if capacity prices do not escalate at the rapid pace that ENO predicts, then the Transmission
Alternative becomes the least-cost alternative under a significant range of capacity market price
forecasts; 394 and
WHEREAS, the Advisors explain that the changing assumptions around the MISO
capacity prices and other inputs have a significant impact on ratepayer bills. 395 For example,
ENO estimates the impact of the CT Alternative on the average residential monthly bill to be
$5.61. 396 However, as Advisors’ witness Watson testifies, once the calculations are adjusted as

389

Advisors’ Post-Hearing Brief at 52, citing Rogers-1 at 36:10-38:6.
Advisors’ Post-Hearing Brief at 52, citing Rogers-1 at 38:7-15.
391
Advisors’ Post-Hearing Brief at 52, citing Rogers-1 at 34:13-35:7.
392
Advisors’ Post-Hearing Brief at 52, citing Rogers-1 at 39:1-42:4.
393
Advisors’ Post-Hearing Brief at 52, citing Rogers-1 at 39:1-42:4.
394
Advisors’ Post-Hearing Brief at 53, citing Rogers-1 at 43:1-45:11.
395
Advisors’ Post-Hearing Brief at 53.
396
Advisors’ Post-Hearing Brief at 53, citing Direct Testimony and Exhibits of Byron S. Watson, Docket No. UD16-02, at 13:3-4 (Nov. 20, 2017) (“Watson-1”).
390

86

 recommended by Mr. Rogers, the rate impact of the CT Alternative increases to $7.33. 397 By
way of comparison, the expected impact of the Transmission Alternative decreases from $6.49
under ENO’s analysis to $1.82, and the RICE Alternative decreases from $7.19 to $6.91; 398 and
WHEREAS, the Advisors acknowledge that the CT Alternative would fully mitigate the
transmission reliability need identified by ENO and confirmed by the Advisors’ own analysis; 399
nevertheless, the Advisors urge that the CT is not in the public interest because it would result in
a significant excess of capacity and subject ENO’s customers to an unacceptable risk of exposure
to unpredictable MISO capacity market prices, and the CT does not have black-start
capability. 400 It has a small emergency diesel generator to supply vital auxiliary loads in the
event of a complete power loss, but the diesel generator is too small to have black-start
capability; 401 and
WHEREAS, ENO witness Charles Long explains that ENO’s current black-start plan
involves a cranking route that begins with restoration of power from the Waterford Unit 4 blackstart resource. 402 Once the Waterford resources are energized those resources would then be
used to continue restoration of power along the Waterford-Ninemile transmission corridor and on
to Michoud to bring power into New Orleans; 403 and
WHEREAS, ENO’s current black-start plan is dependent on lines outside of ENO’s
control. 404 If the transmission grid anywhere along the 40-mile path from Waterford to New
Orleans were damaged, ENO’s ability to provide electric service to ENO customers would be

397

Advisors’ Post-Hearing Brief at 53, citing Watson-1 at 15, Table 5.
Advisors’ Post-Hearing Brief at 53.
399
Advisors’ Post-Hearing Brief at 58; Movish-1 at 20:16-17; C. Long-2 at 2:8-13, 13:7-8; Vumbaco-1 at 21:8-11;
Hr’g Tr. 12/15/17, 124:22-24.
400
Advisors’ Post-Hearing Brief at 58-59; Hr’g Tr. 12/15/17, 230:17-231:3.
401
Advisors’ Post-Hearing Brief at 58 citing Movish-1 at 6:14-15.
402
Advisors’ Post-Hearing Brief at 59, citing C. Long-2 at 28:10-18; C. Long-3 at 31:14-19.
403
Advisors’ Post-Hearing Brief at 59, citing C. Long-2 at 28:10-29:2; C. Long-3 at 31:15-17.
404
C. Long-3 at 31:17-18, 20-21.
398

87

 impaired. 405 Further, ENO has not performed studies demonstrating the feasibility of blackstarting the CT Alternative unit with other generating resources in DSG; 406 and
WHEREAS, the Advisors observe that the Joint Intervenors also oppose the CT
Alternative on environmental grounds. 407 However, the Advisors conclude that ENO has entered
substantial evidence into the record that the CT Alternative will have a significantly reduced
impact compared to the prior units at the Michoud site, that ENO has committed to complying
with all applicable environmental laws and regulations and that ENO has taken steps to mitigate
any potential risk of flooding; 408 and
WHEREAS, the Advisors explain that ENO submitted a technical report into the record
dated November 16, 2016 prepared by C-K Associates, LLC and Losonsky & Associates, Inc.
(“C-K Report”) which addresses the evaluation of groundwater withdrawal and air quality
associated with the proposed CT Alternative. 409 The Advisors state that the C-K Report was
developed to address concerns raised and to understand how the proposed NOPS might impact
subsidence and air quality in New Orleans East; 410 and
WHEREAS, the Advisors state that the C-K Report also concludes that the CT
Alternative’s proposed groundwater withdrawal rate of 96 gallons per minute (“gpm”) is
“relatively low” and will not contribute to subsidence in New Orleans East. 411 The Advisors
state that the report finds by way of comparison, in 1983 there were approximately 200 wells in
the Gonzales-New Orleans aquifer along the Mississippi River from St. Charles to St. Bernard

405

Movish-1 at 38:21-22.
Advisors’ Post-Hearing Brief, citing Movish-1 at 38:1-3, 39:1-3.
407
Advisors’ Post-Hearing Brief at 53.
408
Advisors’ Post-Hearing Brief at 53.
409
Advisors’ Post-Hearing Brief at 53, citing Technical Report - Evaluation of Groundwater Withdrawal and Air
Quality, C-K Associates, LLC and Losonsky & Associates, Inc. (“C-K Report” or “Report”) attached to the
Supplemental Direct Testimony of Jonathan E. Long, Ex. JEL-6 (Nov. 18, 2016) (J. Long-3”).
410
Advisors’ Post-Hearing Brief at 54, citing J. Long-3, Ex. JEL-6 at 1.
411
Advisors’ Post-Hearing Brief at 54, citing J. Long-3, Ex. JEL-6 at 1.
406

88

 Parishes, roughly half of which had flow rates in the range of 1,000 to 2,000 gpm. 412 The
Advisors state that the report concludes that drawdown calculations for the CT Alternative
predict a maximum drawdown over a 10-year period of about one foot near the NOPS pumping
well, diminishing to half of a foot or less at a distance of several thousand feet away, and one
quarter foot or less at a distance of two miles from the well. 413 The Advisors note that the C-K
Report explains that these calculations were performed using the most conservative assumption
that the CT Alternative will operate 24 hours a day, 365 days a year; 414 and
WHEREAS, an additional report, 415 developed and prepared by CB&I Governmental
Solutions, Inc. (“CB&I Report”) and submitted into evidence in this proceeding by ENO, also
reached the same conclusions as those reached in the C-K Report; 416 and
WHEREAS, the Advisors agree that based on the evidence in the record, the
groundwater withdrawal associated with the proposed CT Alternative is unlikely to exacerbate
subsidence or cause damage to infrastructure in New Orleans East. 417 The Advisors find that
ENO presented expert testimony that is well supported by two detailed studies containing site
specific analysis and calculations that also provided historical comparisons to past groundwater
usage. 418 The Advisors conclude that the significantly decreased expected pumping rates for the
CT Alternative reduce the potential for any additional subsidence that may be attributable to
groundwater withdrawal; 419 and

412

Advisors’ Post-Hearing Brief at 54, citing J. Long-3, Ex. JEL-6 at 11.
Advisors’ Post-Hearing Brief at 55, citing Supplemental and Amending Direct Testimony and Exhibits of Dr.
George Losonsky, Docket No. UD-16-02, at 13:16-19 (July 6, 2017) (“Losonsky-1”).
414
Advisors’ Post-Hearing Brief at 55, citing Losonsky-1 at 13:14-21.
415
Advisors’ Post-Hearing Brief at 54 n.238, citing Evaluation of Proposed Groundwater Withdrawals and
Subsidence Entergy New Orleans Power Station, CB&I Governmental Solutions, Inc. (June 16, 2017) (“CB&I
Report”) marked as Exhibit GL-3 and attached to Losonsky-1.
416
Advisors’ Post-Hearing Brief at 54, citing Losonsky-1 at 17:19-22.
417
Advisors’ Post-Hearing Brief at 62.
418
Advisors’ Post-Hearing Brief at 62-63.
419
Advisors’ Post-Hearing Brief at 62.
413

89

 WHEREAS, the Advisors note that the C-K Report also contains an evaluation of the
potential air emissions associated with the operation of NOPS. The C-K Report concluded that
the “emissions from the proposed [CT Alternative] will result from combustion of clean burning
natural gas; in no case, will the emissions cause air quality to exceed regulatory standards, which
are protective of human health and the environment;” 420 and
WHEREAS, the Advisors report that according to ENO witness Bliss M. Higgins, the
CT Alternative would result in a substantial decrease in permitted emissions for NOPS as
compared to the currently permitted Michoud Power Plant. 421 The Advisors state that Higgins
explains that the EPA sets federal air quality standards, formally known as National Ambient Air
Quality Standards (“NAAQS”), to protect public health and the environment, 422 and does so with
an adequate margin of safety. 423 The Advisors point out that Ms. Higgins also explains that
these standards are expressed as an allowable concentration of pollution in the air. The Advisors
note that the C-K Report compared the results of air dispersion modeling for the CT Alternative
to the NAAQS and concluded that the CT Alternative is at least 96% below the NAAQS for all
modeled chemicals and that personal ground-level exposure due to the proposed emissions will
be well below the applicable air standards. 424 The Advisors state that according to ENO, these
conclusions reached in the C-K Report demonstrate that the CT Alternative would not result in
significant adverse air quality effects; 425 and

420

Advisors’ Post-Hearing Brief at 55-56, citing J. Long-3, Ex. JEL-6 at 1.
Advisors’ Post-Hearing Brief at 56, citing Supplemental and Amending Direct Testimony and Exhibits of Bliss
M. Higgins, Docket No. UD-16-02, at 17:32-33 (July 6, 2017) (“Higgins-1”).
422
Advisors’ Post-Hearing Brief at 57, citing Higgins-1 at 32:5-6.
423
Advisors’ Post-Hearing Brief at 57; see also, Revised Rebuttal Testimony of Bliss Higgins, Docket No. UD-1602, at 3:14-16 (Nov. 17, 2017) (“ENO-2”).
424
Advisors’ Post-Hearing Brief at 57; see also, ENO-2 at 14:3-6.
425
Advisors’ Post-Hearing Brief at 57; see also, ENO-2 at 14:6-8.
421

90

 WHEREAS, the Advisors have reviewed the C-K Report and agree that the CT
Alternative would result in a substantial decrease in permitted emissions for NOPS as compared
to the permitted emissions of the prior Michoud units; 426 and
WHEREAS, the Council declines to find that the CAA is a “regulatory fiction,” 427 as is
urged by the Joint Intervenors, 428 nor will the Council find that the process set forth under the
CAA for review of air permit applications is insufficient; and
WHEREAS, the Council observes that the EPA and LDEQ have jurisdiction over the
environmental impacts of the proposed plant. While the Joint Intervenors criticize the applicable
laws and permitting processes as not providing sufficient environmental protection to the citizens
of New Orleans, the Council finds that they do not offer any evidence as to what level of
emissions or environmental harm could be allowed without negative impact to New Orleans, and,
thus, the Council has no record before it upon which it can base a decision to impose a new,
additional environmental standard on ENO. Nor do the Joint Intervenors explain to whom such
an additional standard should be applied ‒ whether to all sources of such emissions in the City or
whether only to ENO and why. Faced with the lack of any such evidence in the record, the
Council declines to adopt new environmental standards in this case, and finds that it will be
sufficient to require ENO to comply with all existing relevant environmental laws and
regulations and to demonstrate its compliance to the Council on an ongoing basis; and
WHEREAS, the Council takes notice of the evidence in the record that the CT would
fully mitigate ENO’s transmission reliability need over the planning period; however the Council
believes that the proposed size of the facility is excessive given ENO’s load forecast, and that it
would subject New Orleans customers to the risk of exposure to unpredictable MISO capacity
426

Advisors’ Post Hearing Brief at 64-65.
Joint Intervenors’ Post-Hearing Brief at 75.
428
Joint Intervenors’ Post-Hearing Brief at 74-75.
427

91

 market revenues. As the Advisors have demonstrated, if ENO’s highly optimistic predictions
about prices in the MISO capacity market prove incorrect, ENO will not be able to offset a
sufficient amount of costs to make the CT economic for ratepayers; and
WHEREAS, the Council also has serious misgivings about the CT unit’s lack of blackstart capability. While a local generating unit in New Orleans would provide important reliability
benefits for the City and the DSG region, given New Orleans’ vulnerability to powerful storms
and its reliance on distant generating units and 40 miles of transmission facilities, including over
open water, to restore power to the City in the event of an outage, the value of local, on-site
black-start generation to support the City’s critical facilities and speed up storm restoration
cannot be understated; and
WHEREAS, for the reasons set forth above, the Council finds that the CT Alternative is
not in the public interest; and
B.

Whether ENO’s selection of a RICE unit is in the public interest

WHEREAS, ENO argues that it has also shown that the RICE Alternative is in the
public interest and is a reasonable alternative to the selection of the CT Alternative to provide
needed capacity and reliability benefits to ENO’s customers. 429 ENO explains that the RICE
Alternative would consist of seven Wärtsilä 18V50SG reciprocating internal combustion engines,
and that it engaged WorleyParsons, a qualified and respected engineering firm, to conduct a
study regarding the Company’s potential options for a smaller resource in the 100-130 MW
range, and their analysis indicated that in that size range, the RICE Alternative had the lowest
levelized cost of electricity on a $/MWh basis of the five technologies considered, low water

429

ENO Post-Hearing Brief at 88.

92

 usage, a low emissions profile, the ability to support renewable resources, and black-start
capability; 430 and
WHEREAS, ENO argues that the RICE Alternative, like the CT Alternative, provides
capacity and reliability benefits to ENO customers. 431 ENO states that the RICE Alternative
addresses ENO’s overall capacity need in the first 10 years of the planning horizon and mitigates
exposure to market and supply related risks, and that it addresses many of the reliability concerns
by preventing the risk of cascading outages. 432 ENO states that although additional transmission
investment may be needed, potential overloads are relatively minor and not anticipated to be an
issue until 2027, which provides the Company time to determine whether it should move forward
with transmission upgrades or consider an additional RICE unit; 433 and
WHEREAS, ENO explains that unlike the CT Alternative, the RICE Alternative can
start and achieve full load in a very short period of time and can start and stop multiple times in a
single day, which is a highly desirable option in a peaking or emergency situation. 434 ENO
argues that this also helps to support renewable resources by providing generation when
renewable resources are not available; 435 and
WHEREAS, ENO argues that the RICE Alternative’s ability to black-start, i.e. start up
under its own power without a backfeed of power from the electric grid, can support storm
restoration after a major outage or storm event and provide a source of power to ENO’s critical
loads in the event of an outage, which is invaluable; 436 and

430

ENO Post-Hearing Brief at 89, citing Supplemental and Amending Direct Testimony and Exhibits of Jonathan E.
Long, Docket No. UD-16-02, at 1, 6-7, and 10 (July 6, 2017) (HSPM) (“J. Long-5”).
431
ENO Post-Hearing Brief at 89.
432
ENO Post-Hearing Brief at 89, citing Cureington-6 at 12 and C. Long-2 at 13.
433
ENO Post-Hearing Brief at 89.
434
ENO Post-Hearing Brief at 90, citing J. Long-5 at 12.
435
ENO Post-Hearing Brief at 90, citing J. Long-5 at 12.
436
ENO Post-Hearing Brief at 90-91, citing J. Long-5 at 13, Movish-1 at 4-5, and Rogers-2 at 51.

93

 WHEREAS, Air Products states that it supports the construction of four or five RICE
units at this point in time as necessary to cover ENO’s current capacity shortfall, and to provide
an acceptable level of reliability to its customers.437 Air Products states that construction of a
RICE facility is clearly in the public interest because of the reliability need for new generation
within the City of New Orleans. 438 Air Products concludes that construction of a RICE facility
would serve the public convenience and necessity, and is in the public interest, and therefore is
prudent. 439

Further, Air Products argues, it is prudent and just and reasonable within the

parameters of the City of Plaquemine v. the Louisiana Public Service Commission, 280 So. 2d
440 (1973) and Federal Power Commission v. Hope Natural Gas Company, 320 U.S. 591, 660
(1944) and a series of cases citing that decision; 440 and
WHEREAS, ENO argues that Air Products’ suggestion that ENO consider adding fewer
than seven RICE units at this time, but construct the infrastructure necessary to permit addition
of the remaining units if future circumstances support adding more capacity is not justified or in
the interest of ENO’s customers. 441 ENO argues that installing fewer than seven units will cost
more on a $/kW basis than the seven-unit plant will cost, and it is not clear that the costs of
mobilizing contractors to the site for a second time in the future and obtaining any necessary
regulatory approvals would support delaying the installation of two or three units from an
economic standpoint. 442 ENO states that there are economies of scale that come with installing
seven RICE units now, and that fewer RICE units would not provide the needed reliability

437

Air Products Post-Hearing Brief at 12
Air Products Post-Hearing Brief at 14.
439
Air Products Post-Hearing Brief at 14.
440
Air Products Post-Hearing Brief at 14.
441
ENO Post-Hearing Brief at 91, citing Brubaker-3 at 3-4.
442
ENO Post-Hearing Brief at 91, citing Cureington-8 at 57-58; and Hr’g Tr. 12/18/17, 129, 132-33. The Council
notes that ENO’s brief refers to $/kWh while Mr. Cureington’s testimony refers to $/kW.
438

94

 benefits of seven RICE units. 443 ENO also points out that Air Products’ witness Mr. Brubaker’s
testimony and observations were based on ENO’s capacity position and not local reliability
benefits as he admitted at the hearing. 444 ENO argues that ENO’s witness Charles Long testified
that reducing the number of RICE units to five would leave ENO with insufficient capacity to
address reliability concerns, and that mitigating reliability concerns is “borderline” with the 128
MW provided by seven RICE units. 445 ENO argues further that it anticipates having a capacity
shortfall of 248 MW by 2036, meaning that ENO will ultimately need the full 128 MW of
capacity that seven units would provide, and that its needs will increase if existing legacy units in
ENO’s portfolio deactivate earlier than expected or if load increases more than projected; 446 and
WHEREAS, NOCS argues that ENO’s selection of the RICE Alternative suffers the
same infirmities as its selection of the CT Alternative, namely (1) ENO’s failure to conduct an
RFP; and that (2) the unit was not selected as a result of the optimization process of the 2015
Final IRP. 447

NOCS concludes that ENO’s manner of selecting the NOPS project was

untethered from any reasonable resource selection process, thumbs its nose at the Council’s
mandated IRP process, and flies in the face of prudent resource planning principles; 448 and
WHEREAS, NOCS states that it understands that the City Council may wish to approve
new generating capacity within the City of New Orleans to enhance the reliability of the
transmission system serving ENO’s customers and that in the event the Council approves any

443

ENO Post-Hearing Brief at 91, citing Hr’g Tr. 12/15/17, 225.
ENO Post-Hearing Brief at 91-92, citing In re. Supplemental and Amending Application of Entergy New Orleans,
Inc., Hearing Transcript, Docket No. UD-16-02 (Dec. 20, 2017), 175-176 (“Hr’g Tr. 12/20/17”).
445
ENO Post-Hearing Brief at 92, citing Hr’g Tr. 12/15/17, 225.
446
ENO Post-Hearing Brief at 92, citing Cureington-8 at 58.
447
NOCS Post-Hearing Brief at 16.
448
NOCS Post-Hearing Brief at 16.
444

95

 new generating resource for ENO, it should only approve the RICE Alternative, and not the CT
Alternative; 449 and
WHEREAS, NOCS notes that the RICE Alternative is less expensive than the CT
Alternative, but that ENO chose to forego generating resource alternatives that were even less
expensive than the RICE Alternative and that this should not be lost on the Council when
addressing cost recovery for the NOPS Project. 450 NOCS believes that placing a cap on the cost
of the NOPS project that may be recovered from ratepayers to protect them from cost overruns
and/or escalations in construction costs due to factors beyond their control would be prudent.451
NOCS argues that given the restrictions on the contract prices for constructing either version of
the NOPS Project, ENO should not be opposed to a cap on cost recovery in the amount of such
caps currently included in the Engineer, Procure, and Construct (“EPC”) contracts; 452 and
WHEREAS, NOCS states that from an operational standpoint, the RICE Alternative
possesses certain attributes that are superior to those of the CT Alternative: (1) it is more flexible
and scalable from a dispatch perspective; (2) it possesses a better heat rate; (3) it will include
black-start capability; (4) it will utilize far less groundwater than the CT Alternative; and (5) it
will provide greater ability to support renewable resources than the CT Alternative. 453 Finally
NOCS notes that the RICE Alternative would resolve nearly all transmission reliability concerns
such that there would only be very minor overloading on the transmission system in year
2027; 454 and

449

NOCS Post-Hearing Brief at 16-17.
NOCS Post-Hearing Brief at 17.
451
NOCS Post-Hearing Brief at 17.
452
NOCS Post-Hearing Brief at 17-18.
453
NOCS Post-Hearing Brief at 18, citing Rogers-1 at 46:15-47:18, J. Long-5 at 11:20-13:19, Rice-3 at 10:5-9,
12:16-20.
454
NOCS Post-Hearing Brief at 19.
450

96

 WHEREAS, the Joint Intervenors argue that the RICE Alternative is not in the public
interest. 455 The Joint Intervenors argue that the Council’s Resolution No. R-17-100 and the
public interest standard require consideration of a broad range of cost, environmental, and public
health considerations. 456 The Joint Intervenors argue that ENO has not met its burden of proving
that NOPS is in the public interest of New Orleans citizens; 457 and
WHEREAS, the Joint Intervenors argue that the Company has not proven a capacity
need or a reliability need for the RICE Alternative; 458 and
WHEREAS, the Joint Intervenors argue that the RICE Alternative is also not the leastcost alternative and would cost ratepayers more than transmission and solar-powered
solutions.459 The Joint Intervenors argue that upgrading New Orleans’ transmission lines and
installing utility-scale solar would be the economically preferred alternative. 460 They argue that
ENO’s case for the RICE Alternative rests heavily on MISO capacity market prices approaching
CONE, allowing New Orleans ratepayers to offset the relatively high construction costs of the
RICE Alternative with capacity sales revenues. 461

Joint Intervenors argue that ENO’s

assumption of a 16,000% increase in the MISO capacity market price by 2022 is unlikely to
occur and is unreasonable. 462 The Joint Intervenors argue that the Advisors’ assessment that the
cost savings for the transmission plus solar is modest, and on balance, should be overcome by the
other collateral benefits of the RICE units, ignores the many detrimental effects of installing the

455

Joint Intervenors’ Post-Hearing Brief at 63.
Joint Intervenors’ Post-Hearing Brief at 63-65.
457
Joint Intervenors’ Post-Hearing Brief at 64.
458
Joint Intervenors’ Post-Hearing Brief at 64.
459
Joint Intervenors’ Post-Hearing Brief at 64.
460
Joint Intervenors’ Post-Hearing Brief at 65.
461
Joint Intervenors’ Post-Hearing Brief at 65.
462
Joint Intervenors’ Post-Hearing Brief at 65-66, citing Direct Testimony and Exhibits of Dr. Elizabeth Stanton,
Docket No. UD-16-02, at 21, Figure 8 (Oct. 16, 2017) (HSPM) (“Stanton-2”), Direct Testimony and Exhibits of
Robert Fagan, Docket No. UD-16-02, at 4:4-5:9 (Oct. 16, 2017) (HSPM) (“Fagan-2”), Rogers-2 at 33:7-11; 36:637:15; Cureington-8, Ex. SEC-15 at 15.
456

97

 RICE units including air pollution, increased risk of subsidence and flooding, and adverse
impacts on the solar and energy efficiency caused by over-supply of generation; 463 and
WHEREAS, the Joint Intervenors argue that ENO failed to adequately assess the
impacts of constructing a gas-fired plant on the environment, including increased air pollution,
subsidence, or flooding. 464 The Joint Intervenors argue that the RICE Alternative would employ
a polluting technology that would place significant environmental burdens on predominately
people of color an poor communities. 465 The Joint Intervenors argue that the RICE Alternative
would create racially disproportionate environmental burdens on predominately African
American and Vietnamese neighborhoods in New Orleans East and that it would release
annually significant amounts of air pollution near homes and schools. 466 The Joint Intervenors
also argue that the RICE Alternative would create significant flood risks that can impact the
same surrounding neighborhoods which have yet to fully recover from the levee failure during
Hurricane Katrina; 467 and
WHEREAS, the Joint Intervenors argue that ENO’s pollution estimates for the RICE
Alternative have not been confirmed by the LDEQ, and that they do not include the amounts of
sulfuric acid or the types and amounts of toxins that would be discharged as water pollution.468
The Joint Intervenors argue that the ambient air quality will worsen with the RICE units’ annual
releases of approximately 1,000,000 pounds of air pollution; 469 and
WHEREAS, the Joint Intervenors claim that ENO argues that the gas plant would meet
the requirements for obtaining air permits; but Joint Intervenors claim this is insufficient and that

463

Joint Intervenors’ Post-Hearing Brief at 66.
Joint Intervenors’ Post-Hearing Brief at 64-65.
465
Joint Intervenors’ Post-Hearing Brief at 67.
466
Joint Intervenors’ Post-Hearing Brief at 67-68.
467
Joint Intervenors’ Post-Hearing Brief at 68.
468
Joint Intervenors’ Post-Hearing Brief at 70.
469
Joint Intervenors’ Post-Hearing Brief at 70.
464

98

 air quality will worsen. 470 The Joint Intervenors argue that across Louisiana, the effects of poor
air quality arise from permitted air pollution, and that air pollution causes cancer, impairs the
function of the respiratory and cardiovascular systems and that “a regulatory standard and a
guarantee of safety are not synonymous.” 471 Joint Intervenors argue that the RICE Alternative
will add to pollution and cause an increase in the risk of adverse health effects, especially for
those who live within the most affected areas around the plant; 472 and
WHEREAS, the Joint Intervenors argue that the air pollutants from the RICE Alternative
would include particulate matter (both PM 2.5 and PM 10 ), sulfur dioxide (SO 2 ), nitrogen oxides
(NO X ), carbon monoxide (CO), greenhouse gases (GHGs) and volatile organic compounds
(VOCs), and that for decades into the future the RICE Alternative will increase the level of
harmful pollutants emitted in New Orleans East communities, and the Council should reject the
plant as contrary to the public interest in a safe and healthy New Orleans, particularly given
ENO’s failure to review other reasonable alternatives; 473 and
WHEREAS, the Joint Intervenors argue that ENO’s witnesses downplayed the harmful
effects of these pollutants, including the sharp increase in PM pollution from present levels. 474
The Joint Intervenors reject the argument that it is relevant that the proposed RICE Alternative
will emit fewer pollutants than the previously-existing power plant on the same site. The Joint
Intervenors also reject the argument that the net reduction in emissions will be sufficient to meet
the minimum CAA permitting requirements, because “[t]he Council is not bound by the CAA
regulatory fiction that allows ENO to pretend that a significant increase in harmful pollutants is

470

Joint Intervenors’ Post-Hearing Brief at 70.
Joint Intervenors’ Post-Hearing Brief at 71, citing Thurston-2 at 8, and Johnson v. Orleans Parish School Board,
975 So. 2d at 711.
472
Joint Intervenors’ Post-Hearing Brief at 71.
473
Joint Intervenors’ Post-Hearing Brief at 74-75.
474
Joint Intervenors’ Post-Hearing Brief at 75.
471

99

 actually a decrease in those pollutants and find that the public interest requires a focus on the
actual emissions from either gas plant;” 475 and
WHEREAS, the Joint Intervenors argue that the anticipated emissions from the RICE
Alternative will not meet minimum federal standards because they will be significant enough to
trigger the EPA’s specific requirements for emissions control and analysis; 476 and
WHEREAS, the Joint Intervenors argue that the provision of the CAA that allows ENO
to avoid more stringent review by netting the emissions from the old Michoud units against the
proposed units prevents a proper evaluation of the anticipated emissions from the plant; 477 and
WHEREAS, the Joint Intervenors argue that air pollution causes decreased lung function,
more frequent asthma symptoms, increased numbers of asthma and heart attacks, more frequent
emergency department visits, additional hospital admissions, and increased numbers of deaths
and a host of additional health impacts; 478 and
WHEREAS, the Joint Intervenors argue that the RICE Alternative is not in the public
interest because it would violate the Council’s policy on climate change. 479

The Joint

Intervenors argue that the Council has adopted a policy to reduce the City’s greenhouse gas
emissions and pursue renewable energy and energy efficiency to address climate change and that
both NOPS alternatives are counterproductive to those goals. 480 The Joint Intervenors also argue
that NOPS would be counter to the City’s Climate Action for a Resilient New Orleans plan and

475

Joint Intervenors’ Post-Hearing Brief at 74-75.
Joint Intervenors’ Post-Hearing Brief at 76-77.
477
Joint Intervenors’ Post-Hearing Brief at 76.
478
Joint Intervenors’ Post-Hearing Brief at 77-79, citing Direct Testimony and Exhibits of Dr. George Thurston,
Docket No. UD-16-02, at 5-8, 10, and 25 (Jan. 6, 2017) (“Thurston-1”).
479
Joint Intervenors’ Post-Hearing Brief at 82-84.
480
Joint Intervenors’ Post-Hearing Brief at 82-84.
476

100

 strategy to reduce its greenhouse gas emissions by 50% by 2020 and to goal of 255 MW of solar
by 2030; 481 and
WHEREAS, the Joint Intervenors argue that ENO’s proposed RICE Alternative would
increase flood risks and could violate the City’s flood protection ordinance, and would conflict
with FEMA critical-infrastructure guidance; 482 and
WHEREAS, the Joint Intervenors argue that the RICE Alternative is not in the public
interest because it was selected outside of the public participation and IRP Process. 483 The Joint
Intervenors argue that the fact that the Council entered into a settlement agreement with ENO in
a public FERC docket regarding the termination of the System Agreement that included the
provision requiring ENO to explore 120 MW of new-build peaking generation in New Orleans
pre-determined the positions that ENO and the Advisors would take in this proceeding and that
the record in this case provides no alternative explanation for their positions. 484 The Joint
Intervenors speculate that the Settlement Agreement holds such strong sway over this proceeding
that it caused ENO and the Advisors to reject the least cost and reasonable alternatives to a gas
plant, such as renewable and efficient energy systems, DSM, and increased electric capacity of
the transmission system. 485; and
WHEREAS, the Joint Intervenors argue that the Settlement Agreement substantially
undermined the 2015 IRP process and that there is a lack of transparency in this docket regarding
the Settlement Agreement because Council Resolutions No. R-16-332, R-16-506 and R-17-426
do not discuss it. 486 The Joint Intervenors argue that due process has been violated because there

481

Joint Intervenors’ Post-Hearing Brief at 84-86.
Joint Intervenors’ Post-Hearing Brief at 87-88.
483
Joint Intervenors’ Post-Hearing Brief at 88.
484
Joint Intervenors’ Post-Hearing Brief at 89-90.
485
Joint Intervenors’ Post-Hearing Brief at 90.
486
Joint Intervenors’ Post-Hearing Brief at 91.
482

101

 is no assurance that the prior Settlement Agreement does not in any way pre-determine the
outcome of the decisions leading up to the one that is anticipated from the Council in this case.487
The Joint Intervenors criticize the Council and the Advisors for failing to take action in this
docket to “resolve the due process issues that arise from the prior agreement;” 488 and
WHEREAS, the Advisors conclude that the RICE Alternative presents the most viable
alternative for the Council’s consideration in the instant docket to resolve ENO’s current
transmission system reliability issues. 489 The Advisors agree with ENO’s analysis that the RICE
Alternative is capable of fully mitigating the NERC reliability issues over the planning period if
coupled with future transmission upgrades (in the 2027 time frame). The Advisors state that if it
turns out in 2027 that ENO does need to make transmission upgrades, the locally-sited RICE
Alternative would “unload” the transmission lines so that ENO would likely be able to get the
transmission outage necessary to complete the upgrades; 490 and
WHEREAS, the Advisors state that under the economic analyses modeled either with or
without the Council’s 2% DSM Goal, there is not much difference between the RICE Alternative
and the CT Alternative. 491 However, the Advisors argue, the RICE Alternative is a better fit
with ENO’s load and capability needs, especially when considering the Council’s 2% DSM
Goal. 492 The Advisors state that there are two additional factors that must be considered as well:
(1) the level of certainty in the capital cost estimates, and (2) several physical parameters of the
RICE Alternative that potentially make it operationally more attractive to the Council. 493 With
respect to the capital cost estimates, the estimates for the RICE Alternative and the CT

487

Joint Intervenors’ Post-Hearing Brief at 91-92.
Joint Intervenors’ Post-Hearing Brief at 92.
489
Advisors’ Post-Hearing Brief at 60.
490
Advisors’ Post Hearing Brief at 61, 69.
491
Advisors’ Post-Hearing Brief at 72, citing Rogers-1 at 51:5-19.
492
Advisors’ Post-Hearing Brief at 72, citing Rogers-1 at 51:5-19.
493
Advisors’ Post-Hearing Brief at 72, citing Rogers-1 at 46:1-7, 51:5-19.
488

102

 Alternative are fairly certain and based upon negotiated EPC contracts. 494 On the other hand, the
Advisors argue, the transmission cost estimates are based on generic high-level cost per milebased estimates rather than a cost estimate based on a specific design. 495 The Advisors find that
the uncertainty in the transmission capital cost estimates is a concern that should be considered
as well. 496 In short, the Advisors explain, the RICE Alternative presents a lesser economic risk
than either the CT Alternative or the Transmission Alternative because its capacity is more
aligned with ENO’s forecasted capacity needs than are both the CT Alternative, which offers
more capacity than ENO needs in the near term and the Transmission Alternative, which offers
no new capacity; 497 and
WHEREAS, the Advisors state that with respect to the physical parameters of the RICE
Alternative, the RICE Alternative is expected to operate at a lower capacity factor than the CT
Alternative, would be dispatched in a more economic operating mode than the CT Alternative,
the RICE unit is more flexible with respect to commitment and dispatch and is a better fit for the
generation needs of the region, the RICE Alternative can more precisely match part load
requirements and can most likely be dispatched with the RICE Alternative engines operating at
or near their most efficient operating points. 498 The Advisors state that at its full load operation,
the RICE Alternative has a heat rate that is roughly 18% better than the CT Alternative, therefore
it would have lower per MWh fuel costs as well as being less susceptible to fuel; and
WHEREAS, the Advisors point out that the RICE Alternative is expected to take
roughly one year less to construct than the CT Alternative, meaning that ENO’s NERC reliability
issues would be addressed sooner by the RICE Alternative than by the CT Alternative, and far
494

Advisors’ Post-Hearing Brief at 72, citing Rogers-1 at 46:8-14.
Advisors’ Post-Hearing Brief at 72, citing Rogers-1 at 46:8-14.
496
Advisors’ Post-Hearing Brief at 72, citing Rogers-1 at 46:8-14.
497
Advisors’ Post-Hearing Brief at 72, citing Vumbaco-1 at 25:3-7.
498
Advisors’ Post-Hearing Brief at 73, citing Rogers-1 at 46:15-47:18.
495

103

 more quickly than a “No NOPS” (transmission-only) scenario particularly given the
constructability challenges that the Company must overcome in order to implement any
transmission upgrades; 499 and
WHEREAS, the Advisors agree that the modular nature of the proposed RICE
Alternative is an advantage. 500 The Advisors explain that these units can be operated separately,
so that the capacity committed can be matched more closely to actual system needs -- if one unit
goes down, others can continue to run. 501 The Advisors also state that the forced outage rate of
the RICE units is lower than for the CT, which makes them an inherently more reliable choice,
and the smaller revenue requirement would have a lesser impact on ratepayers because it there is
less exposure to capital costs; 502and
WHEREAS, the Advisors agree with ENO that it is not appropriate to install only four to
five of the units at this time and to wait to install additional units in the future. 503 The Advisors
do not believe that this would meet the reliability need of ENO. The Advisors also assert that
this approach would add costs over the long term; 504 and
WHEREAS, the Advisors argue that the RICE Alternative also would provide other
significant benefits to New Orleans, including operational flexibility, dynamic system support
for voltage regulation; reduction of dependence on transmission to import power and reduction
in the need to construct additional river-crossing transmission for at least 10 years; provision of
reactive power support, which would increase the reliability of the surrounding transmission
system and enhances its ability to appropriately respond to system disturbances; and on-site

499

Advisors’ Post Hearing Brief at 68-69.
Advisors’ Post-Hearing Brief at 66-68, citing Brubaker-2 at 9:4-16.
501
Advisors’ Post-Hearing Brief at 67, citing Brubaker-2 at 9:4-9.
502
Advisors’ Post-Hearing Brief at 71-73.
503
Advisors’ Post-Hearing Brief at 67, citing Hr’g Tr. 12/18/17, 335:7-336:2.
504
Advisors’ Post Hearing Brief at 68.
500

104

 black-start capability to ability to provide a source of power to ENO’s critical loads and to
support restoration of service after a major outage or storm event; 505 and
WHEREAS, the Advisors agree with ENO that a local resource with black-start
capability, in close electrical proximity to the electric demand, would enable much more
effective voltage and frequency response during the black-start process and therefore would
greatly enhance ENO’s ability to restore electric service, should a complete loss of service on the
electric system occur, such as in the event of a major storm. 506 Having local generation in the
City that provides a dependable source of black-starting power and avoids the risks of
transmission failure is especially important given that ENO’s system exists in an extreme
weather event region. 507 The CT Alternative does not have this very important feature, and
therefore, from a reliability standpoint, the Advisors believe that other alternatives, such as the
RICE Alternative, would be preferable to the construction of the CT Alternative; and
WHEREAS, the Advisors note that a facility with on-site black-start capability might
also be able to assist in restarting the motors at the S&WB pumping station in the event of a loss
of electrical service, but that this would be subject to further study. 508 In the Advisors’ view,
having black-start capability would be critical to insuring that local generation could be
depended upon to power S&WB’s pumping plant, in the event of a failure of S&WB’s
generators during critical flooding events; 509 and

505

Advisors’ Post-Hearing Brief at 68-70; C. Long-2 at 26:4-28:2.
Advisors’ Post-Hearing Brief at 70; C. Long-2 at 28:2-29:7-11. C. Long-3 at 31:21-32:1.
507
Advisors’ Post-Hearing Brief at 70, citing Movish-1 at 40:1-5.
508
Advisors’ Post Hearing Brief at 70; C. Long-3 at 44:17-45:18; Movish-1 at 5, 8-9.
509
Advisors’ Post-Hearing Brief at 73; Movish-1 at 9:13-16.
506

105

 WHEREAS, similar to the CT Alternative, reports submitted by ENO into the record510
conclude that the groundwater withdrawal associated with the RICE Alternative will not
exacerbate ground subsidence or cause damage to infrastructure in New Orleans East. 511 Based
on engineering estimates provided by ENO’s equipment vendor and contractor, the anticipated
pumping rate for the RICE Alternative is less than one tenth of the pumping rate for the CT
Alternative. 512 When compared to the deactivated Michoud units, the RICE Alternative usage
rate will result in a 99.9% groundwater use reduction; 513 and
WHEREAS, the Advisors find it significant that ENO witness Ms. Higgins provided
similar analyses regarding the level of emissions anticipated from the RICE Alternative, and
concluded that the RICE Alternative would result in a substantial decrease in permitted
emissions for the NOPS as compared to the currently permitted Michoud Power Plant; 514 and
WHEREAS, the Joint Intervenors argue that there is no safe level of exposure to certain
pollutants. 515 Specifically, witness Thurston opined that “any increase in pollution will increase
the risk of adverse effects at all levels of prevailing air pollution, even when the NAAQS
standards are not violated. 516 Joint Intervenors also disagree that NAAQS are effective or that
meeting NAAQS air quality standards prevents significant adverse health effects from occurring
in the exposed population. 517 The Advisors disagree with this assertion. 518 They explain that
simply because a source creates emissions greater than zero does not necessarily infer significant

510

Advisors’ Post-Hearing Brief at 62, citing Addendum to the C-K Associates Technical Report of November 16,
2016: Evaluation of Predicted Drawdown and Consolidation Settlement Resulting from Proposed NOPS Pumping
(“Addendum to C-K Report”), attached to Losonsky-1 as Exhibit GL-2.
511
Advisors’ Post-Hearing Brief at 62, citing Losonsky-1 at 6:21-23.
512
Advisors’ Post-Hearing Brief at 63, citing Losonsky-1, Ex. GL-2 at 2.
513
Advisors’ Post-Hearing Brief at 63, citing Losonsky-1, Ex. GL-2 at 2.
514
Advisors’ Post-Hearing Brief at 64, citing Higgins-1 at 17:32-33, 50:9-15; see also, ENO-2 at 14:9-11.
515
Advisors’ Post-Hearing Brief at 56, citing Thurston-1 at 15:5-6.
516
Advisors’ Post-Hearing Brief at 56, citing Thurston-1 at 17:13-15.
517
Advisors’ Post-Hearing Brief at 57, citing Thurston-1 at 18:6-7.
518
Advisors’ Post-Hearing Brief at 58.

106

 adverse health effects. 519 The Advisors believe that if this logic were accepted, the vast majority
of vehicles and manufacturing facilities across the country would be prohibited from operation
because they violate the “more than zero” standard that the Joint Intervenors have advanced in
this case. 520 While the Advisors support clean sources of energy, especially renewables when
cost effective and appropriate, responsible energy policymaking requires consideration of a
number of factors that inform decisions to acquire new resources; 521 and
WHEREAS, the Advisors agree with ENO’s witness, Higgins that the RICE Alternative
would result in a substantial decrease in permitted emissions for NOPS as compared to the
currently permitted Michoud Power Plant. 522 While it is extremely important for ENO to have
generating capacity in New Orleans for reliability purposes, this generation must be clean,
efficient and have no significant impact on the environment. 523 The Advisors conclude that the
RICE Alternative is the best option to meet ENO’s reliability issues and avoid any adverse
impact on public health or the environment. C-K Associates concluded, and the Advisors agree,
that the evidence presented by ENO shows that the predicted ambient concentrations from the
RICE Alternative are well below the NAAQS for all modeled chemicals; 524 and
WHEREAS, the Council finds that ENO has committed to operate the plant in an
environmentally safe manner and to comply with all EPA, LDEQ and local laws and
regulations; 525 and

519

Advisors’ Post-Hearing Brief at 58.
Advisors’ Post-Hearing Brief at 58.
521
Advisors’ Post-Hearing Brief at 58.
522
Advisors’ Post-Hearing Brief at 57; see also, ENO-2 at 50:11-15.
523
Advisors’ Post-Hearing Brief at 57.
524
Advisors’ Post-Hearing Brief at 65.
525
Advisors’ Post-Hearing Brief at 66, citing Hr’g Tr. 12/20/17, 132:21-25, 133:1-12.
520

107

 WHEREAS, the Council finds that it has been shown that the RICE Alternative has the
ability to resolve ENO’s current transmission system reliability issues, mitigate risk and provide
operational flexibility; and
WHEREAS, the record indicates that the RICE Alternative and the CT Alternative are
similarly attractive in terms of economics. However, as noted above, the Council does not
measure the public interest determination based on economics alone. Determining whether a
proposal is in the public interest requires the Council to balance all relevant factors and no single
element of the public interest should be considered in isolation; and
WHEREAS, the Council notes favorably the testimony of Advisors’ witness Vumbaco,
who aptly describes the public interest standard as “a ‘net benefits’ test, but such a test
encompasses more than a simple algorithm or numerical analyses and often results in a
subjective balancing of interests by the regulator in making its determination.” 526

The Council

has an obligation to evaluate all aspects of ENO’s proposal in connection with the need it will
serve, and in so doing, to weigh the benefits of ENO’s choices of technology to determine if they
are justified by the costs. The Council must also consider reliability needs with respect to
transmission, voltage and regulation support, transmission constructability issues, the benefits of
black-start capability, and storm restoration considerations when considering a path forward for
New Orleans; and
WHEREAS, the record supports the conclusion that the RICE Alternative is less
sensitive to changes in the MISO capacity market prices, has a better heat rate, and operationally
provides more dispatch flexibility than the CT or Transmission Alternatives. When considering
the MISO capacity market, transmission constructability uncertainty, operation and economic

526

Redacted Direct Testimony & Exhibits of Joseph Vumbaco, Docket No. UD-16-02, at 11:1-4 (Nov. 20, 2017)
(“Vumbaco-1”).

108

 risk to ratepayers, the generation alternative that best hedges and partially mitigates such risk is
the construction of the RICE Alternative in combination with the incorporation of renewable
technologies and realistically achievable DSM potential in ENO’s service territory; and
WHEREAS, ENO presented expert testimony that is well supported by two detailed
studies containing site specific analysis and calculations that also provided historical
comparisons to past groundwater usage. The Council is persuaded by the evidence presented by
ENO that the risk of subsidence resulting from groundwater withdrawal is de minimis
considering the expected pumping rate for the RICE Alternative is less than one tenth of the
pumping rate for the CT Alternative. The Council also finds it compelling that ENO’s evidence
demonstrates that when compared to the deactivated Michoud units, the RICE Alternative usage
rate will result in a 99% groundwater use reduction, even if operated 24 hours a day, 365 days a
year; and
WHEREAS, the Council finds that ENO has shown that the RICE Alternative is in the
public interest because: (1) it resolves a critical and immediate reliability need and will do so for
at least a decade; (2) it is more appropriately sized to meet the City’s anticipated capacity needs
in accordance with ENO’s load forecast; (3) it provides operational flexibility that will support
incorporation of renewables into ENO’s generation portfolio, a key goal of the Council and the
City; (4) it will result in a significant reduction in groundwater use compared to the prior
Michoud plant, and below even the CT Alternative; (5) it is expected to result in a reduction in
air emissions associated with the new units as compared with the prior Michoud plant which
operated within the City for half a century until just two years ago; and, (6) importantly, it has
on-site black-start capability, which will support ENO’s critical loads in the event of an outage

109

 and will aid in restoration efforts after a storm, a very valuable feature given the City’s
susceptibility to extreme weather; and
WHEREAS, based upon the record in this proceeding and the information provided in
ENO’s application, including transmission models and underlying assumptions, as well as the
parties’ evaluation of this information, and for the reasons set forth above, the Council concludes
that ENO has shown that its selection of the RICE technology serves the public interest,
assuming that ENO complies with all applicable laws and regulations, including, but not limited
to, compliance with all EPA and LDEQ requirements; and
C.

Whether ENO appropriately considered a full range of options to
meet the identified need

WHEREAS, ENO argues that it appropriately considered a full range of options to meet
its identified supply needs. 527 It explains that (1) ENO’s 2015 Final IRP included an extensive
review of options for meeting the long-term needs of the Company’s customers; (2) possibilities
other than new gas-fired generation would not meet ENO’s supply and reliability needs, and
(3) a formal competitive process to select a resource addition for ENO would have been costly to
customers and wasteful considering the Company’s specific supply and reliability needs; 528 and
WHEREAS, ENO argues that its 2015 IRP process determined that CT capacity is the
best alternative to meet ENO’s identified supply need, and subsequent analyses confirm that
result and that the RICE resource is a reasonable alternative that provides many of the same
benefits as the proposed CT. 529 ENO argues that Joint Intervenors’ witness Mr. Fagan contends
that ENO did not perform a rigorous analysis of resource alternatives, but that he ignores ENO’s
2015 Final IRP, and confirmed at the hearing that he had not reviewed it in preparing his

527

ENO Post-Hearing Brief at 92.
ENO Post-Hearing Brief at 92.
529
ENO Post-Hearing Brief at 92.
528

110

 testimony. 530 ENO argues that in its 2015 Final IRP, ENO conducted a DSM Potential Study,
Generation Technology Assessment, and Portfolio Evaluation and documented the extensive
analysis undertaken and stakeholder input sought over the course of nearly 18 months of work
including hundreds of hours of data review, modeling, post-processing analysis, stakeholder
review, public technical conferences, and reports to the Council. 531

ENO argues that the

extensive 2015 IRP process resulted in the conclusion that ENO has a substantial need for
peaking and reserve capacity and that a CT unit is the lowest reasonable cost resource capable of
meeting that need. 532 and
WHEREAS, ENO states that it has considered other options to meet its need, such as
other natural gas technology, transmission upgrades, and a combination of solar, DSM, and
batteries, and that none of these options meet ENO’s reliability and capacity needs, nor do they
provide the same benefits as NOPS. 533 ENO states that it conducted technology assessments in
2016, March 2016, November 2016, and Spring 2017 which evaluated a total of at least 14
different gas-fired generation technologies, and concluded that the 226 MW CT is the most costeffective alternative, and with the seven Wärtsilä RICE units has the lowest levelized cost of
electricity of generators in the 100-130 MW range; 534 and
WHEREAS, ENO states that transmission upgrades are not a viable alternative to
constructing NOPS. 535 ENO argues that transmission can only move power around, it cannot
produce electrical energy, capacity or much-needed dynamic reactive power in the DSG load
pocket. 536 ENO notes that its analysis determined that five transmission upgrades need to be

530

ENO Post-Hearing Brief at 93, citing Fagan-2 at 10, Hr’g Tr. 12/19/17, 16-17.
ENO Post-Hearing Brief at 93, citing Cureington-2 at 9, Cureington-8 at 59.
532
ENO Post-Hearing Brief at 93, citing Cureington-8 at 59.
533
ENO Post-Hearing Brief at 94.
534
ENO Post-Hearing Brief at 94-95.
535
ENO Post-Hearing Brief at 95.
536
ENO Post-Hearing Brief at 95.
531

111

 constructed in the absence of NOPS, and that there are significant concerns regarding
constructability of those upgrades, including soil condition, obstructions, and environmental
challenges that would increase the cost of construction. 537 ENO submitted testimony that the
outages required to make these upgrades would span many months over many peak hours and
that getting enough outages to construct the upgrades could take years because the outages can
only be taken at the lowest load times, and expressed skepticism that it can be done at all; 538 and
WHEREAS, ENO argues that with respect to some combination of renewable resources,
increased DSM, and battery resources, those resources are not an adequate replacement for
NOPS. 539 ENO argues that all are speculative and do not guarantee that ENO can produce
energy when and where it is needed. 540 ENO argues that these options are not consistent with its
current supply need. 541 ENO argues that no witness has put forth testimony that ENO could
count on renewable resources, DSM and batteries to solve its reliability issues and that none of
the Joint Intervenors’ witnesses have put forth a specific combination of resources to meet both
capacity and reliability needs, much less an economic analysis of costs to ENO’s customers; 542
and
WHEREAS, ENO argues that a more formal RFP process was not necessary to identify
and evaluate ENO’s supply options, and it would have been costly to customers. 543 ENO argues
that a formal RFP or competitive all-source solicitation to fulfill its identified resource needs was
unwarranted for several reasons: (1) a specific types of generation are needed at a specific
location (a peaking resource at Michoud) and holding an open-source RFP to encourage other

537

ENO Post-Hearing Brief at 95.
ENO Post-Hearing Brief at 95, citing Hr’g Tr. 12/15/17, 171, 193-194 and 197-198.
539
ENO Post-Hearing Brief at 96.
540
ENO Post-Hearing Brief at 96.
541
ENO Post-Hearing Brief at 96.
542
ENO Post-Hearing Brief at 96.
543
ENO Post-Hearing Brief at 96.
538

112

 types of resources at other locations will not meet this specific need; (2) the Council’s rules and
regulations do not require that an RFP be conducted prior to adding generating capacity intended
to serve Council-jurisdictional customers; and (3) Joint Intervenors’ witness Mr. Henderson
recognized that there may be legitimate reasons why a utility or utility regulator might determine
not to use a competitive resource requirement and that one such reason is that they are expensive
and take time to complete. 544 In this case, ENO argues, it would have been improper to saddle
customers with the cost of an RFP process or all-source solicitation. 545 ENO notes that the fact
that it already owns the Michoud site gives it a likely cost advantage over any other potential
supplier, ENO’s need for peaking capacity cannot be met through DSM or intermittent supplyside resources, and because there are no local generating resources in New Orleans, relying on
PPAs would be inappropriate. 546 ENO concludes that the unique aspects of ENO’s capacity and
reliability needs, the costs of an RFP process or all-source solicitation would not have been in the
interest of ENO’s customers. 547 ENO also points out that the major cost component of ENO’s
proposed self-build, the , EPC Contract, was tested through a competitive selection process, that
together with other risk mitigation measures provide protections for customers that serve the
public interest; 548 and
WHEREAS, Air Products states that is not aware of any alternative technology option
that would be feasible and should have been considered; 549 and
WHEREAS, Air Products argues that ENO appropriately considered the availability and
practicality, as well as the economics of additional resources, including solar resources, wind

544

ENO Post-Hearing Brief at 96-97.
ENO Post-Hearing Brief at 97.
546
ENO Post-Hearing Brief at 97-98.
547
ENO Post-Hearing Brief at 98.
548
ENO Post-Hearing Brief at 98.
549
Air Products Post-Hearing Brief at 12.
545

113

 resources, and other resources. 550 Air Products notes that ENO has chosen to include 50 MW of
solar resources in its capacity expansion plan along with the NOPS unit, and argues that this is a
reasonable amount of solar generation to be added to the system, but that it is an intermittent
resource which is available only at such times as there are normal amounts of sunshine; 551 and
WHEREAS, Air Products argues that attempts to include larger amounts of solar
resources, instead of RICE units, would subject ENO’s customers to an intolerable risk of
outages because solar cannot be counted on fully to perform at times of high system loads. 552
Air Products argues that there are practically no available wind resources that could serve load
without substantial amounts of investment in transmission. 553 Air Products states that wind
resources typically have their highest output at night-time in winter, when the output is least
needed to serve load, so that even if it were practically available and economic, it would not
fulfill peak needs in New Orleans; 554 and
WHEREAS, Air Products disputes the Joint Intervenors’ suggestion to use interruptible
load as a resource. 555

Air Products states that it is a customer that has part of its load

interruptible because the nature of its operations allows for a certain amount of storage. 556 It
states that it is unaware of any other customers interested in, or, importantly, capable of taking,
interruptible power in New Orleans. 557 Air Products also states that should interruptions increase
beyond the level contemplated in the Large Interruptible Service tariff, it is very possible that Air
Products would no longer be able to tolerate the use of interruptible power and would convert to

550

Air Products Post-Hearing Brief at 12.
Air Products Post-Hearing Brief at 12.
552
Air Products Post-Hearing Brief at 13.
553
Air Products Post-Hearing Brief at 13.
554
Air Products Post-Hearing Brief at 13.
555
Air Products Post-Hearing Brief at 13.
556
Air Products Post-Hearing Brief at 13.
557
Air Products Post-Hearing Brief at 13.
551

114

 all firm power. 558 Finally, Air Products notes that when ENO evaluates its loads and resources,
it fully recognizes the interruptible nature of the load and removes it from its net load obligation,
thus ENO’s capacity deficit of about 100 MW already assumes Air Products’ 20 MW of
interruptible load will be interrupted. Air Products states that if it were not interruptible, ENO’s
deficit would be about 20 MW higher than what its load and capacity statement already
shows; 559 and
WHEREAS, NOCS argues that the Council should find that ENO neglected to consider
the full range of options to meet the purported need for capacity. NOCS characterizes ENO’s
selection process as arbitrary and unsupported because in selecting the CT Alternative (which
contradicted its own AURORA model results), ENO selected the self-build CT Alternative
without testing the market. 560 NOCS argues that an RFP process is an appropriate way to test the
market to determine the full range of credible options when a utility needs additional capacity. 561
NOCS argues that ENO’s process for selecting the NOPS project was so flawed, and excluded so
many potentially more economic resources, that ENO cannot show that it selected the least
costly option, and that prudence dictates a comparison of a selected resource to alternatives as
part of the showing of least cost; 562 and
WHEREAS, NOCS argues that ENO’s Louisiana affiliates are required by the Louisiana
Public Service Commission (“LPSC”) to conduct formal RFPs when acquiring or constructing
new long-term generating resources. 563 NOCS also argues that any electric public utility must

558

Air Products Post-Hearing Brief at 13.
Air Products Post-Hearing Brief at 13.
560
NOCS Post-Hearing Brief at 19.
561
NOCS Post-Hearing Brief at 19.
562
NOCS Post-Hearing Brief at 19.
563
NOCS Post-Hearing Brief at 20.
559

115

 show that its actions are prudent and reasonable. 564 NOCS argues that ENO can only meet its
burden of showing that its decision-making in electing to construct the NOPS project was
prudent and reasonable by showing that NOPS is the least-cost option among alternatives, NOCS
assets that, because ENO failed to issue an RFP its application is fatally flawed and must be
dismissed; 565 and
WHEREAS, NOCS argues that ENO neglected to consider the full range of options to
meet any identified need because it didn’t fully analyze a transmission solution. 566 NOCS argues
that ENO categorically ruled out a transmission option as a solution to resolve the transmissionrelated reliability need, and as a result, chose to evaluate the Transmission Alternative only as an
afterthought; 567 and
WHEREAS, the Joint Intervenors argue that ENO’s application failed to consider an
adequate range of alternatives to the proposed gas-fired plants, including specific alternative
portfolios that the Council ordered ENO to evaluate so that the Council could make an informed
decision in this proceeding. 568 The Joint Intervenors argue that, despite the Council’s order to do
so, ENO has never assessed in a single portfolio (1) the potential for making transmission
upgrades to remain compliant with NERC reliability standards; (2) installing the planned 100
MW of solar; (3) implementing the Council’s 2% DSM Goal; and (4) the inclusion of battery
storage. The Joint Intervenors argue that because ENO has yet to even attempt the alternatives
analysis the Council required, and is therefore in violation of a Council resolution, the Council

564

NOCS Post-Hearing Brief at 20-21, citing Gulf States Utils. Co. v. Louisiana Pub. Serv. Comm’n, 578 So. 2d 71
(La. 1991); Alliance for Affordable Energy, Inc. v. Council of the City of New Orleans, 578 So.2d 949, 973-74 (La.
App. 4th Cir. 1991), vacated after consent decree at 588 So. 2d 89 (La. 1991); S. Central Bell Telephone v.
Louisiana Pub. Serv. Comm’n, 352 So. 2d 964, 972-973 (La. 1977), cert. denied, 437 U.S. 911, 98 S. Ct. 3103, 57 L.
Ed. 2d 1142 (1978) (finding that “ratepayers should not bear the burden of a utility’s imprudence.”).
565
NOCS Post-Hearing Brief at 22-23.
566
NOCS Post-Hearing Brief at 24-26.
567
NOCS Post-Hearing Brief at 25.
568
Joint Intervenors’ Post-Hearing Brief at 92.

116

 should deny ENO’s application as incomplete. 569

NOCS argues that ENO could construct

additional transmission capacity and access generating capacity through purchases. 570 NOCS
states, however, that the Advisors are correct that ENO’s evaluation of the Transmission
Alternative is woefully inadequate – in its current state – to support a decision to pursue that
option; 571 and
WHEREAS, the Joint Intervenors also argue that the Council in Resolution No. R-16506 ordered ENO to specifically evaluate a set of four portfolios designed by the Advisors, but
that ENO did not run those portfolios, including the “Case 2” portfolio that resembles the
combination of resources recommended by Joint Intervenor’s witness Mr. Fagan. 572 Rather Joint
Intervenors argue, ENO used a load forecast that did not include the 2% DSM Goal which made
its version of Case 2 appear more costly and therefore less attractive than building a gas-fired
plant. 573 Joint Intervenors also argue that ENO never evaluated the possibility of a battery
resource in Case 2, or in any case in which it would not also build a gas-fired plant; 574 and
WHEREAS, the Joint Intervenors argue that ENO’s method of selecting the contractors
for these projects demonstrates that a competitive process is necessary to protect ratepayers. 575
The Joint Intervenors argue that ENO failed to use a competitive procurement process to select
its two proposed gas plants, making it impossible to determine whether they are the best, leastcost resources to meet the City’s needs. 576 Joint Intervenors urge the Council to reject ENO’s
application and require the Company to conduct a competitive procurement process; 577 and

569

Joint Intervenors’ Post-Hearing Brief at 92.
NOCS Post-Hearing Brief at 25.
571
NOCS Post-Hearing Brief at 26.
572
Joint Intervenors’ Post-Hearing Brief at 93-95.
573
Joint Intervenors’ Post-Hearing Brief at 95.
574
Joint Intervenors’ Post-Hearing Brief at 95.
575
Joint Intervenors’ Post-Hearing Brief at 96.
576
Joint Intervenors’ Post-Hearing Brief at 97.
577
Joint Intervenors’ Post-Hearing Brief at 97.
570

117

 WHEREAS, the Joint Intervenors argue that a competitive procurement process would
provide the following benefits (1) transparency for regulators and stakeholders; (2) cost
proposals that are based on market conditions; (3) bids that reflect competitive pressures,
offering the best value for the money; (4) full documentation of financial and engineering
assumptions used to develop bids; (5) power supply and demand-side resources that are
evaluated on an equal footing; (6) assessment of a complete set of both conventional and
innovative alternatives; and (7) creative solutions from a wider marketplace, based on the latest
technology. 578

The Joint Intervenors argue that the ENO team procuring contractors was

instructed to examine only gas-fired peaker plants, and that rather than conducting an open
solicitation, ENO spoke to only six companies, and only four of those companies participated by
submitting bids. 579 Moreover, the Joint Intervenors argue that ENO limited the RFP for the CT
Alternative to specifically request a Mitsubishi 501GAC gas turbine, and they limited their
search to companies they were aware of that did that sort of work. 580 Thus, the Joint Intervenors
argue, from the beginning ENO had no intention of evaluating alternatives to the gas-fired
peaker plant, and did not issue an RFP stating it had transmission needs and generation needs
and asking for proposals on how to resolve these concerns; 581 and
WHEREAS, the Joint Intervenors argue ENO’s process for selection of the RICE
Alternative contractor fares no better. 582 The Joint Intervenors argue that ENO’s process was
insufficient because it only requested bids from two contractors; 583 and

578

Joint Intervenors’ Post-Hearing Brief at 97-98.
Joint Intervenors’ Post-Hearing Brief at 98.
580
Joint Intervenors’ Post-Hearing Brief at 98.
581
Joint Intervenors’ Post-Hearing Brief at 98-99.
582
Joint Intervenors’ Post-Hearing Brief at 99.
583
Joint Intervenors’ Post-Hearing Brief at 99.
579

118

 WHEREAS, the Joint Intervenors urge the Council to disregard ENO’s arguments that
an RFP is unnecessary because ENO had a specific need for local dispatchable generation
resources and it decided that DSM and the supply-side resources would not be sufficient. 584 The
Joint Intervenors argue that ENO’s process is simply a failed version of traditional utility
procurement and that while this type of solicitation, if done correctly, may deliver price
competition, the bidding does not address the fundamental question of whether building a power
plant is the optimal use of customer funds. 585 In contrast, the Joint Intervenors argue, an allsource competitive solicitation would provide information about costs and benefits of any
resource alternatives that could potentially fulfill the utility’s needs and adds confidence that the
resource selected is the least-cost resource; 586 and
WHEREAS, the Joint Intervenors argue that ENO’s selection method was not a
competitive solicitation at all, and thus, the Council cannot even be assured that the price to be
paid by ratepayers is reasonable or fair because with such a small sample size and the lack of
transparency surrounding how the potential bidders were selected, it is impossible for the
Council to know whether costs associated with either NOPS plant proposal adequately reflect the
market; 587 and
WHEREAS, the Joint Intervenors argue that ENO’s selection process is illustrative of a
pervasive problem of utility culture that prefers traditional solutions and avoids innovation.588
They argue that it ignores the fact that the market landscape for utility resources has changed
substantially in recent years; 589 and

584

Joint Intervenors’ Post-Hearing Brief at 100.
Joint Intervenors’ Post-Hearing Brief at 100.
586
Joint Intervenors’ Post-Hearing Brief at 100-101.
587
Joint Intervenors’ Post-Hearing Brief at 101.
588
Joint Intervenors’ Post-Hearing Brief at 101.
589
Joint Intervenors’ Post-Hearing Brief at 101.
585

119

 WHEREAS, the Advisors argue that while more data is generally preferable when
making decisions based on highly technical information, and a more extensive use of the
AURORA model’s optimizations functions would have been beneficial, the Council has more
than enough information before it to render a decision in this case, particularly in light of
significant, ongoing risk to ratepayers which will only be exacerbated by further delay. 590 The
Advisors state that ENO has identified a reasonable range of options to meet the specific
identified needs in this case, and record contains sufficient information to decide on ENO’s
application; 591 and
WHEREAS, the Advisors note that while an IRP process was not performed as part of
ENO’s application, ENO’s application was significantly informed by the analysis it performed in
its 2015 Final IRP. They report that as part of its 2015 Final IRP, ENO performed a technology
assessment in which ENO screened a wide range of generation technologies to define a set of
reference supply-side generation technologies that would be modeled in the IRP process. 592 The
final set of supply-side generation technologies included: pulverized coal generation, CTs,
CCGT, internal combustion engines, generation from biomass, nuclear, wind, solar, and battery
storage; 593 and
WHEREAS, the Advisors argue that the need for some level of generation in the City
has long been known to ENO and the Advisors, and was certainly identified in the 2015 IRP
process. In fact, the preferred portfolio identified in ENO’s 2015 Final IRP analysis included a
250 MW CT, which is consistent with ENO’s 226 MW CT Alternative. 594 The Advisors explain
that the reduction in size and change in technology that led to the RICE Alternative proposal was
590

Advisors’ Post-Hearing Brief at 75.
Advisors’ Post-Hearing Brief at 75.
592
Advisors’ Post-Hearing Brief at 75, citing Rogers-1 at 14:4-9.
593
Advisors’ Post-Hearing Brief at 75, citing Rogers-1 at 14:4-9.
594
Advisors’ Post-Hearing Brief at 76.
591

120

 due largely to the availability of new data acquired and analyses performed since the close of the
2015 IRP process. 595 The Advisors also state that ENO’s analyses in both the 2015 Final IRP
and in this docket are further informed by the input from the Advisors that the initial analyses
needed to be supplemented to ensure that the Council has enough information to make a
reasoned decision; 596 and
WHEREAS, the Advisors explain that ENO did perform a significant amount of analysis
of various technologies and portfolios in the 2015 IRP process. 597 They state that with regard to
peaking technologies modeled in the IRP, ENO included six different internal combustion engine
CT technologies ranging from 19 MW to 194 MW. 598 Further, the Advisors argue, ENO ran the
AURORA optimization process in the 2015 Final IRP and it chose a 382 CCGT in three of the
four scenarios run and 1,150 MW of solar with 50 MW of wind in the fourth scenario run. 599
ENO did not choose a CCGT, however, instead chose a 194 MW CT unit for its preferred
portfolio, arguing that such a unit was better suited to meet the peaking power need identified in
the IRP than a CCGT. 600 In performing additional production cost analyses at the request of the
Advisors and Intervenors, ENO increased the size to a 250 MW CT; 601 and
WHEREAS, the Advisors state that neither the size nor the timing of the project was
optimized as part of the IRP process, and 602 the current timing of either the CT or the RICE
Alternative appears to be “as soon as possible” based upon the anticipated schedule durations for

595

Advisors’ Post-Hearing Brief at 76.
Advisors’ Post-Hearing Brief at 76.
597
Advisors’ Post-Hearing Brief at 76.
598
Advisors’ Post-Hearing Brief at 76, citing Rogers-1 at 14:9-11.
599
Advisors’ Post-Hearing Brief at 76, citing Rogers-1 at 14:16-15:24.
600
Advisors’ Post-Hearing Brief at 76, citing Rogers-1 at 14:16-15:24.
601
Advisors’ Post-Hearing Brief at 76, citing Rogers-1 at 16:4-13.
602
Advisors’ Post-Hearing Brief at 76, citing Rogers-1 at 17:11-18:2.
596

121

 each of the alternatives. 603 The Advisors believe that this suggests that ENO cannot solely rely
on the economic analyses presented in the IRP to demonstrate a case for the NOPS unit; 604 and
WHEREAS, the Advisors state that ENO has provided three sets of economic analyses
in this proceeding: one set with the Initial Application, one set as part of the supplemental
testimony and one set with the Supplemental Application. 605 The Advisors note that the Initial
Application generally provided a screening analysis of CT Alternatives. 606 They explain that the
supplemental testimony was required by Council Resolution No. R-16-506 and was in response
to a September 19, 2016 request by the Council’s Advisors for ENO to perform additional
AURORA IRP modeling to assist the Council in determining whether the construction of NOPS
is necessary and in the public interest. 607 The Advisors state that, the analyses included with the
Supplemental Application were also developed utilizing the AURORA production cost modeling
software and were, in part, informed by the Advisors’ recommendations; 608 and
WHEREAS, the Advisors made their September 19, 2016 request that ENO perform
additional analyses because the Advisors believed that over the 20 months it had taken ENO to
perform the 2015 IRP and in the time since the 2015 Final IRP was filed, several important
developments had occurred that were not reflected in the 2015 Final IRP analysis. 609
Specifically, the Advisors explain, these were: (1) the acquisition of the Algiers service territory
and its associated customer load; (2) the Council’s expression of its 2% DSM Goal; (3) the
increase in size of the Union Power Block 1 (“UPS”) acquisition; (4) the suggestion that there
may be a Transmission Alternative to the installation of NOPS; (5) the revised, dramatically

603

Advisors’ Post-Hearing Brief at 76-77, citing Rogers-1 at 17:11-18:2.
Rogers-1 18:7-8.
605
Advisors’ Post-Hearing Brief at 77, citing Rogers-1 18:11-19:3.
606
Advisors’ Post-Hearing Brief at 77, citing Rogers-1 18:11-19:3.
607
Advisors’ Post-Hearing Brief at 77, citing Rogers-1 18:11-19:3.
608
Advisors’ Post-Hearing Brief at 77, citing Rogers-1 18:11-19:3.
609
Advisors’ Post-Hearing Brief at 78, citing Rogers-1 at 19:3-21:2.
604

122

 different load forecast; (6) the commitment by ENO to pursue AMI; and (7) ENO’s commitment
to seek up to 100 MW of renewables. 610 The Advisors felt that all of these developments and
changes could result in material increases in costs to ratepayers and could alter the ultimate
decision of the Council with respect to the project. 611 The Advisors state that they requested the
alternate case analyses to ensure that the Council had additional current information to inform
their decisions on the NOPS proposal and other issues in the near term - decisions that would
likely be made prior to the next iteration of the triennial IRP process; 612 and
WHEREAS, the Advisors state that the four additional cases that the Advisors asked
ENO to model generally built off what had been the Stakeholder Input Case from the 2015 IRP
process with updated assumptions including: (1) a load forecast consistent with the BP16 update;
(2) a natural gas price forecast consistent with the BP16 update; (3) an updated CO 2 price
forecast; (4) an increase in the renewable capacity to 100 MW; (5) inclusion of the effects of
planned and recently completed transmission upgrades; and (6) inclusion of the effects of any
planned new generating resources in the region, including the proposed St. Charles Power
Station; 613 and
WHEREAS, the Advisors state that each of the four alternate cases was designed by the
Advisors to isolate the impact of an individual decision by changing only one assumption against
a common base case so that the cost impact of that individual decision could be identified. 614
The Advisors explain that the three decision points to be tested in the Advisors’ requested cases
were (1) NOPS versus transmission upgrades; (2) pursuit of the 2% DSM Goal; and (3) impact

610

Advisors’ Post-Hearing Brief at 78, citing Rogers-1 at 19:3-21:2.
Rogers-1 at 19:3-21:2.
612
Rogers-1 at 19:3-21:2.
613
Rogers-1 at 21:3-13.
614
Rogers-1 at 21:14-23:20.
611

123

 of AMI on DSM. 615 However, after reviewing the results of the analyses performed by ENO in
response to the request, the Advisors do not recommend that the Council rely upon the outcome
of these analyses because (1) they cannot be directly compared to the analyses presented in the
Supplemental Application due to the change in the load forecast; (2) they do not contain a
scenario with the RICE Alternative; and (3) they only partially take into account the Council’s 2%
DSM Goal due to ENO’s choice to use a breakeven analysis that calculated the level of DSM
investment that would result in the same net present value as the base case, rather than analyzing
a full implementation of the 2% DSM Goal; 616 and
WHEREAS, the Advisors state they provided further input to ENO prior to its filing of
the Supplemental Application as to the minimum level of analysis that should be included in that
application. 617 The Advisors sought to ensure that ENO provided the Council with a 20-year
economic analysis that (1) included current and consistent assumptions including the Council’s 2%
DSM Goal; (2) was based on utilizing the AURORA optimization engine and included at least
two optimized portfolios with one being the re-sized NOPS alternative (in this manner the
Council would have a least cost optimized portfolio to compare with the NOPS proposal);
(3) included sensitivities that addressed fuel costs and capacity prices, and (4) included the
associated transmission load flow analyses consistent with the economic analyses. 618

The

Advisors state that this analysis was designed to partially mimic a portion of the IRP
optimization process.
recommendations.

620

619

However, ENO only partially adhered to the Advisors’

The Advisors argue that the results presented in ENO witness

615

Rogers-1 at 21:14-23:20.
Advisors’ Post-Hearing Brief at 79, citing Rogers-1 at 21:14-23:20.
617
Advisors’ Post-Hearing Brief at 79, citing Rogers-1 at 24:11-20.
618
Advisors’ Post-Hearing Brief at 80, citing Rogers-1 at 24:11-20.
619
Advisors’ Post-Hearing Brief at 80, citing Rogers-1 at 24:11-20.
620
Advisors’ Post-Hearing Brief at 80, citing Rogers-1 at 25:3-8.
616

124

 Cureington’s Supplemental and Amending Direct Testimony as “requested portfolios” are not
actually what the Advisors requested, nor are they based on optimization analyses; 621 and
WHEREAS, the Advisors note that in addition to the analyses ENO submitted
supporting the CT Alternative, in response to the updated load forecast, ENO engaged
WorleyParsons to conduct a study regarding the Company’s potential options for a smaller
resource. 622 The Advisors state that Company looked at potential CT and RICE Alternatives
with a net plant output between 106 MW and 128 MW and ultimately concluded that the
currently proposed 128 MW RICE Alternative had the lower levelized cost of electricity on a
$/MWh basis as well as other benefits such as low water usage, a low emissions profile, the
ability to support renewable resources, and black-start capability; 623 and
WHEREAS, the Advisors thus conclude that the initial analysis indicating that a CT
resource should be added to ENO’s portfolio was performed in the 2015 IRP process, but the
actual proposal before the Council has been informed by a significant additional amount of
analysis and new information that has since become available. 624 The Advisors argue that this is
appropriate, and indeed necessary, because the IRP is not, and never has been, intended to be a
process that gathers sufficient data to approve or deny the acquisition of any specific resource.
Rather, the Advisors explain, under the rules in place at the time the Initial Application was filed,
the IRP process was intended to provide a framework to help guide ENO in its decisions to
(1) develop generation resources and purchase power both individually and in conjunction with
its affiliate Operating Companies pursuant to the System Agreement; (2) develop transmission
and distribution facilities both individually and in conjunction with its affiliate Operating

621

Advisors’ Post-Hearing Brief at 80, citing Rogers-1 at 25:3-8.
Advisors’ Post-Hearing Brief at 80, citing Rogers-1 at 17:2-7.
623
Advisors’ Post-Hearing Brief at 80, citing Rogers-1 at 17:2-7.
624
Advisors’ Post-Hearing Brief at 80.
622

125

 Companies pursuant to the System Agreement; (3) develop and deploy demand-side resource
options and (4) incorporate into its planning process the results of energy efficiency programs
developed at the direction of the Council (e.g., Energy Smart New Orleans and others as may
subsequently be determined to be applicable). 625 The Advisors state that there has never been a
requirement that any specific resource acquisition precisely match the IRP results; rather, the IRP
rules in effect for the 2015 Final IRP provided that “[t]he Council will consider the Utility’s IRP
status reports, implementation of the requirements and the Utility’s success in achieving its
objectives in rate-making proceedings that address among other things the prudency of costs
incurred by the Utility to construct generation, and purchase and deliver electricity.” 626
Moreover, as discussed above, the Council’s resolution regarding the 2015 Final IRP was very
clear that acceptance of the 2015 Final IRP Report by the Council would not constitute binding
precedent in this case; 627 and
WHEREAS, the Advisors note that the Joint Intervenors argue that the Transmission
Alternative to NOPS will address the transmission system deficiencies at a considerably lower
capital cost than NOPS, and that ENO has not given thorough consideration to adding
transmission capacity as an alternative to building NOPS. 628 However, the Advisors argue, the
Joint Intervenors’ primary witness supporting this assertion, Mr. Lanzalotta, admits that he
conducted no independent analysis or study regarding any aspect of the feasibility of competing
the transmission upgrades; 629 and

625

Advisors’ Post-Hearing Brief at 81, citing Resolution No. R-10-142 at 6 (Mar. 25, 2010).
Advisors’ Post-Hearing Brief at 81, citing Electric Utility Integrated Resource Plan Requirements of the Council
of the City of New Orleans, Attachment to Resolution No. R-10-142, at 7.
627
Advisors’ Post-Hearing Brief at 81-82.
628
Advisors’ Post-Hearing Brief at 82, citing Lanzalotta-1 at 2:19-3:2.
629
Advisors’ Post-Hearing Brief at 82, citing Hr’g Tr. 12/21/17, 76:7-24.
626

126

 WHEREAS, the Advisors also observe that Joint Intervenors’ witness Mr. Fagan, who
argues that transmission reinforcement to meet NERC reliability requirements is feasible and
more cost-effective than building a new gas-fired power plant 630 and who speculates that other
steps could be taken to reduce peak load on the system over time, which can have a material
effect on the timing requirements for any require transmission reinforcements and ease outage
scheduling difficulties, 631 admitted on cross-examination that when he prepared his testimony, he
had not done any studies to determine the feasibility of outage scheduling for transmission lines
into the ENO service area for the next 10 years, and that he has never planned or operated
transmission in MISO South. 632 The Advisors conclude that his speculation as to how easily
transmission upgrades can be accomplished appears to lack any foundation; 633 and
WHEREAS, the Advisors conclude that there is simply not enough evidence in the
record to demonstrate that the Transmission Alternative is viable. 634 The Advisors express
significant concerns that the Transmission Alternative is likely significantly more expensive than
ENO estimated, and that it will take much longer to solve the transmission reliability issue
through transmission upgrades than through adding local generation such as the RICE
Alternative; 635 and
WHEREAS, the Advisors also observe that ENO witness Cureington testified that
portfolios that involve building transmission alone and/or adding renewable capacity are not
viable planning alternatives to building a local, dispatchable peaking resource. 636 The Advisors
note that Cureington testified that he believes that the Total Relevant Supply Costs are

630

Advisors’ Post-Hearing Brief at 82, citing Fagan-1 at 5:10-6:15; 36:18-38:11.
Advisors’ Post-Hearing Brief at 82, citing Fagan-1 at 35:2-36:1.
632
Advisors’ Post-Hearing Brief at 83, citing Hr’g Tr. 12/19/17, 32:3-15.
633
Advisors’ Post-Hearing Brief at 83, citing Hr’g Tr. 12/19/17, 32:3-15.
634
Advisors’ Post-Hearing Brief at 83.
635
Advisors’ Post-Hearing Brief at 83.
636
Advisors’ Post-Hearing Brief at 83, citing Cureington-5 at 5:10-13.
631

127

 understated because his calculations only include transmission upgrades to maintain NERC
reliability requirements and do not address either the additional resources required to meet the
identified needs of ENO’s customers, or market and supply risks. 637 The Advisors state that
Cureington argues that the Transmission Alternative leaves New Orleans too dependent upon
transmission to serve the needs of its customers; 638 and
WHEREAS, the Advisors state that their witness Mr. Rogers did conclude that of the
cases modeled, the economically preferred alternative appears to be construction of transmission
upgrades and 100 MW of solar capacity instead of constructing NOPS. 639 However, they add,
Mr. Rogers went on to emphasize that the Council should not base its decision in this docket
solely on economics and that he believes that reliance on this Transmission Alternative poses
potentially excessive risk to ENO’s customers. 640 If the Council determines it will not approve
either the CT Alternative or the RICE Alternative, Advisors state that their witness Mr. Movish
cautioned that the Transmission Alternative should not be considered as a realistic alternative
until such time as ENO files additional information with the Council; 641 and
WHEREAS, the Advisors also inform the Council that the timing, and cost of
completion of the necessary transmission upgrades required to resolve ENO’s NERC system
reliability violations is uncertain. 642 Further detailed evaluations and cost estimates would be
needed prior to final Council approval of such an option, and the Advisors recommend that the
Council should consider the current risk of system reliability occurrences that could persist until
the transmission upgrades were complete and weigh this risk as compared to the RICE

637

Advisors’ Post-Hearing Brief at 83, citing Cureington-5 at 29:9-31:15.
Advisors’ Post-Hearing Brief at 84, citing Cureington-5 at 29:9-31:15.
639
Advisors’ Post-Hearing Brief at 84, citing Rogers-1 at 3:1-9; 50:4-51:4.
640
Advisors’ Post-Hearing Brief at 84, citing Rogers-1 at 3:1-9; 50:4-51:4.
641
Advisors’ Post-Hearing Brief at 84, citing Movish-1 at 47:3-9; see also, Rogers-1 at 3:1-9; 50:4-51:4.
642
Advisors’ Post-Hearing Brief at 84, citing Vumbaco-1 at 27:9-16.
638

128

 Alternative and the CT Alternative whose construction completion dates can be comparatively
and reliably forecasted and whose costs are comparatively more certain. 643 Advisors’ witness
Vumbaco recommended that, should the Council chose the Transmission Alternative to address
the reliability problems that exist today and are expected to continue in the future unless
corrected, more information regarding the viability of this alternative is needed and the Council
should immediately direct ENO to file with the Council information demonstrating (i) that a
transmission only solution to the reliability problems is realistically achievable; (ii) that its
proposed upgrade projects can in fact be constructed, (iii) the realistic timing of each project,
(iv) the potential impacts of each project’s delay on ENO’s transmission reliability, and (v) the
definitive costs for each project. Such filing should be required within the ensuing six to nine
months for its evaluation and final approval prior to its implementation; 644 and
WHEREAS, the Advisors conclude that alternatives that rely on transmission upgrades
may be technically feasible, however, the Advisors have significant concerns regarding the
constructability of the Transmission Alternative’s transmission upgrades. 645 The Advisors are
also concerned that ENO is uncertain of the feasibility of constructing such transmission
upgrades in terms of timing and cost.646 The Advisors argue that the Council should carefully
weigh the risk to New Orleans related to potential delays in implementing alternatives based on
transmission. 647 While the Transmission Alternative may be the most economically attractive,
the Advisors believe it carries significant risks that should be quantified when compared to the
CT or RICE Alternatives; 648 and

643

Advisors’ Post-Hearing Brief at 84, citing Vumbaco-1 at 27:9-16.
Advisors’ Post-Hearing Brief at 85, citing Vumbaco-1 at 7:1-7.
645
Advisors’ Post-Hearing Brief at 85, citing Vumbaco-1 at 23:1-14; Movish-1 at 26:13-14, 46:15-47:24.
646
Advisors’ Post-Hearing Brief at 85, citing Vumbaco-1 at 23:1-14; Movish-1 at 26:10-13, 46:15-47:24.
647
Advisors’ Post-Hearing Brief at 85, citing Vumbaco-1 at 23:1-14; Movish-1 at 29:4-6, 48:5-9.
648
Advisors’ Post-Hearing Brief at 85, citing Vumbaco-1 at 25:7-13.
644

129

 WHEREAS, the Advisors also recommend that, in addition to the doubtful nature of
whether the Transmission Alternative can actually be implemented in time to prevent a
significant outage, if at all, it would not be prudent to rely on the MISO capacity market to
address ENO’s long-term capacity needs. 649 While the Joint Intervenors argue that ENO should
rely upon the MISO capacity market to meet long-term reliability needs, the Advisors state that
their argument is based on speculation that future MISO capacity market prices will stay low, a
claim that is as unfounded as ENO’s speculation that prices will escalate rapidly. 650

The

Advisors state that Joint Intervenors’ witness Mr. Fagan argues that ENO understates MISO’s
resource surplus and overstates MISO’s future capacity prices, obscuring the substantial
economic risk to New Orleans ratepayers of building a new gas plant that is not needed. 651
However, the Advisors report that Mr. Fagan admitted upon cross-examination that in
recommending a transmission-only option with reliance on the MISO capacity market to meet
capacity needs, he was not familiar with and did not address or do any analysis of narrow
constrained areas within MISO South. 652 The Advisors also report that Mr. Fagan also did no
studies to determine the feasibility of outage scheduling for transmission lines into the ENO
service area for the next 10 years. 653 Similarly, the Advisors state that Joint Intervenors’ witness
Dr. Stanton, who argues that ENO could meet its MISO capacity and NERC transmission
obligations by purchasing market capacity and that transmission upgrades are less expensive than
and provide more resilience than building NOPS, 654 admitted in cross-examination that she has
no training or experience in transmission system planning or utility operations, leaving one to

649

Advisors’ Post-Hearing Brief at 86, citing Rogers-1 at 31:1-2, 15-20, 32:1-7.
Advisors’ Post-Hearing Brief at 86.
651
Advisors’ Post-Hearing Brief at 86, citing Fagan-1 at 4:4-5:9; 16:13-32:19.
652
Advisors’ Post-Hearing Brief at 86, citing Hr’g Tr. 12/19/17, 31:10-19.
653
Advisors’ Post-Hearing Brief at 86, citing Hr’g Tr. 12/19/17, 32:7-12.
654
Advisors’ Post-Hearing Brief at 86, citing Stanton-1 at 7:9-11; 35:6-8; 44:1-7.
650

130

 wonder upon what she has based her opinion. 655 Further, the Advisors argue, neither Fagan nor
Stanton has done any independent projection of MISO capacity prices, 656 nor have they done any
independent analyses regarding the feasibility of the transmission-only solution; 657 and
WHEREAS, the Advisors state that it would not be appropriate to rely on the MISO
PRA market to meet long-term resource needs and ENO should acquire resources to match load
requirements over the long term. 658 The Advisors argue that the MISO PRA should generally be
used to meet limited short-term differences in resources consistent with what the Company has
argued; 659 and
WHEREAS, the Advisors argue that if the Joint Intervenors are correct as to the
projected capacity prices remaining low, then the risk to ratepayers is that they will pay too much
for ENO to build capacity, when they could have gotten cheaper capacity from the market, while
if ENO is correct in its assumptions, ratepayers are subject to the risk of high prices for capacity
in the market, and they are also subject to the risk of cascading outages and/or load shedding.
The Advisors’ assessment is that it is more risky to rely on the MISO capacity market for longterm planning needs than to build generation; 660 and
WHEREAS, with regard to the Joint Intervenors’ arguments that (1) ENO has not
examined a sufficient number of other options, such as meeting its capacity and reliability needs
through increased investment in energy efficiency and DSM, DG, renewables, and battery
storage; 661 (2) ENO should have analyzed additional scenarios, including one that incorporates
the most cost-effective levels of energy efficiency, one that assesses a higher-efficiency scenario
655

Advisors’ Post-Hearing Brief at 86, citing Hr’g Tr. 12/21/17, 11:19-22.
Advisors’ Post-Hearing Brief at 86, citing Hr’g Tr. 12/19/17, 30:3-19, 31:1-9, Hr’g Tr. 12/21/17, 13:3-15.
657
Advisors’ Post-Hearing Brief at 86, citing Hr’g Tr. 12/19/17, 32:6-15; Hr’g Tr. 12/21/17, 26:4-9.
658
Advisors’ Post-Hearing Brief at 87, citing Rogers-1 at 32:1-8.
659
Advisors’ Post-Hearing Brief at 87, citing Rogers-1 at 34:1-12.
660
Advisors’ Post-Hearing Brief at 88.
661
Advisors’ Post-Hearing Brief at 88, citing Stanton-1 at 6:12-14; 25:1-26:11; 26:12-27:8; 27:9-28:3; Luckow-1 at
25:13-26:2; Fagan-1 at 4:4-5:9; 6:16-7:8; 7:9-16; 7:19-8:5; 10:15-12:3 14:3-15:23; 16:1-12.
656

131

 combined with the lower estimate of the MISO capacity market’s future clearing prices, one with
additional solar PV beyond the initial 100 MW in combination with the most cost-effective
energy efficiency portfolio; one that would defer or eliminate some of the required transmission
reinforcement needs indicated under its reference portfolios, and one that in the near future could
include bulk system battery storage resources; 662 and (3) these resources can help meet peaking
needs by reducing overall demand, 663 the Advisors do not find the Joint Intervenors’ witnesses to
be convincing; and
WHEREAS, the Advisors report that in cross-examination Mr. Fagan admitted that
when he prepared his testimony in this case, he had not (1) reviewed ENO’s 2015 Final IRP or
any materials from that proceeding; 664 (2) run any AURORA production cost models, capacity
expansion modeling packages or power flow modeling, (3) performed any economic analysis
demonstrating the cost impact to ENO’s customers of the different possibilities he mentions;
(4) actually proposed any specific basket of resources to meet the identified needs, (5) performed
an analysis of how much DSM should be achievable in New Orleans, (6) analyzed the amount
of solar capacity that can be located in New Orleans or the DSG load pocket, (7) conducted an
independent study to forecast solar PV costs or the expected installation rate of solar in New
Orleans, (8) placed a specific number on the amount of DSG that could be guaranteed to be
achieved in New Orleans (nor could he do so), (9) done any analysis on the feasibility of
installing 200 MW of solar in New Orleans, (10) done any analysis of the economic viability of
battery storage in MISO, or (11) analyzed how actions that ENO takes would lower the load or

662

Advisors’ Post-Hearing Brief at 88, citing Fagan-1 at 12:4-14:2.
Advisors’ Post-Hearing Brief at 88, citing Fagan-1 at 24:15-25:1; Stanton-1 at 26:12-27:8.
664
Advisors’ Post-Hearing Brief at 89, citing Hr’g Tr. 12/19/17, 16:20-25.
663

132

 additional transmission investment would mitigate against the contingencies they’re concerned
about; 665 and
WHEREAS, the Advisors also explain that when asked if he would guarantee that
renewables and DSM alone would keep the lights on in New Orleans in the event that a storm
takes out the transmission grid and leaves New Orleans electrically islanded, Mr. Fagan replied,
“No. nobody could.” 666 He also admitted that behind-the-meter solar is not particularly likely to
be able to support storm restoration. 667

The Advisors argue that it is clear that the Joint

Intervenors’ witness Fagan was not familiar with what options ENO had considered through the
2015 IRP process, nor did he recommend any specific basket of resources, nor had he done any
relevant analysis to determine what is actually feasible in New Orleans or at what cost; 668 and
WHEREAS, the Advisors argue that Joint Intervenors’ witness Dr. Stanton admitted on
cross-examination she had not done any analysis of her own demonstrating whether the 2% DSM
Goal is an achievable goal. 669

The Advisors also note that Dr. Stanton agreed on cross-

examination that if you decrease your load forecast to account for a particular DSM forecast and
that DSM forecast does not materialize, customers would be exposed to capacity market price
risks 670 and that the level of savings from AMI is uncertain; 671 and
WHEREAS, the Advisors also report that Dr. Stanton admitted she does not know the
location of any of the potential 100 MW of renewables ENO plans to add 672 and that she also
admitted she had not performed any analysis of the expected solar installation rates in New

665

Advisors’ Post-Hearing Brief at 89, citing Hr’g Tr. 12/19/17, 17:22-13, 19:15-23, 21:2-13, 22:8-13, 23:3-6,
25:15-19, 26:6-14, 35:4-23, 35:25-36:6, 36:7-18, 36:19-24, 41:13-25.
666
Advisors’ Post-Hearing Brief at 89, citing Hr’g Tr. 12/19/17, 37:10-16.
667
Advisors’ Post-Hearing Brief at 89, citing Hr’g Tr. 12/19/17, 38:3-6.
668
Advisors’ Post-Hearing Brief at 89.
669
Advisors’ Post-Hearing Brief at 90, citing Hr’g Tr. 12/21/17, 28:2-6.
670
Advisors’ Post-Hearing Brief at 90, citing Hr’g Tr. 12/21/17, 28:7-13.
671
Advisors’ Post-Hearing Brief at 90, citing Hr’g Tr. 12/21/17, 21:25-22:3.
672
Advisors’ Post-Hearing Brief at 90, citing Hr’g Tr. 12/21/17, 22:12-15.

133

 Orleans over the next 20 years or any analysis of the projected costs of behind-the-meter solar in
New Orleans, and was not familiar with ENO’s net metering rate schedule. 673 The Advisors
state that she admits that she has no analysis to support the trajectory of behind-the-meter solar
growth that she calculated in her Figure 7 674 and that she did not perform an analysis with
respect to the duration that behind-the-meter or utility scale battery storage could provide
capacity when needed. 675 They also report that Dr. Stanton admitted that she did not perform an
analysis of the potential costs of either behind-the-meter solar or utility scale battery storage over
the 20-year planning horizon, had not analyzed the capacity that either could provide 676 and has
not done any analysis of the amount and price of capacity that might be available for ENO for
wind PPAs or whether transmission would be available to import remote wind resources, and
does not offer an opinion as to whether importing remote wind capacity into New Orleans would
support reliability in the DSG load pocket. 677 The Advisors report that Dr. Stanton agrees that
investment in the distribution system is not a viable alternative to addressing ENO’s capacity
needs 678 and that she stated that she did not propose any specific alternative portfolio of
resources for the Council to consider. 679 In short, the Advisors argue, Dr. Stanton offers no
viable plan to the Council to meet the identified reliability and capacity needs, she merely offers
speculation unsupported by any analysis of what is feasible and achievable in New Orleans as to
other options that she thinks might work; 680 and
WHEREAS, the Advisors do not believe that the specific reliability and peaking
capacity needs at issue in this proceeding, including NERC P6 contingencies, can be met by the
673

Advisors’ Post-Hearing Brief at 91, citing Hr’g Tr. 12/21/17, 23:14-24:4.
Advisors’ Post-Hearing Brief at 91, citing Hr’g Tr. 12/21/17, 24:11-20.
675
Advisors’ Post-Hearing Brief at 91, citing Hr’g Tr. 12/21/17, 25:17-22.
676
Advisors’ Post-Hearing Brief at 91, citing Hr’g Tr. 12/21/17, 24:24:22-25:16.
677
Advisors’ Post-Hearing Brief at 91, citing Hr’g Tr. 12/21/17, 25:23-26:18.
678
Advisors’ Post-Hearing Brief at 91, citing Hr’g Tr. 12/21/17, 27:8-11.
679
Advisors’ Post-Hearing Brief at 91, citing Hr’g Tr. 12/21/17, 20:16-21.
680
Advisors’ Post-Hearing Brief at 91.
674

134

 types of resources Joint Intervenors advocate, and thus, believe ENO has sufficiently evaluated a
reasonable range of resources for the purpose of meeting its identified need. 681 The Advisors
note that ENO does continue to examine and pursue other resources, and has committed to
adding 100 MW of renewables to its portfolio, but these resources cannot offset the need for
local, dispatchable, all-weather generation; 682 and
WHEREAS, the Advisors state that while they appreciate the desire of the Joint
Intervenors to encourage ENO to acquire a greater percentage of its energy from renewable
resources, natural gas is still needed to back up those renewables and offset their intermittency to
keep the grid stable and reliable. 683 The Advisors state that natural gas resources enable greater
integration of renewables into the system, and that even Joint Intervenors’ witness Fagan stated
that customers benefit from natural gas generation, that most anticipated firm additions in MISO
over the next 10 years will be gas generation, and that natural gas fired capacity will continue to
be an important part of the U.S. energy mix for the foreseeable future; 684 and
WHEREAS, the Advisors believe that relying upon the analysis in this case as evidence
that the identified capacity and reliability needs of New Orleans can be met through a
combination of transmission upgrades and other resources such as renewables, DG, energy
efficiency, DSM and battery storage is unreasonable and too risky; 685 and
WHEREAS, the Advisors argue that ENO’s inconsistent peak load assumptions as
between its transmission studies and economic studies when considering the amount of DSM
peak load reductions that would occur with the continued implementation of the Council’s 2%
DSM Goal, and uncertainty about the appropriate capacity factor of any potential solar
681

Advisors’ Post-Hearing Brief at 91-92.
Advisors’ Post-Hearing Brief at 92.
683
Advisors’ Post-Hearing Brief at 94.
684
Advisors’ Post-Hearing Brief at 95, citing Hr’g Tr. 12/19/17, 32:23-33:25, 36:25-37:8.
685
Advisors’ Post-Hearing Brief at 95.
682

135

 generation calls into question the veracity of such studies. 686 The Advisors also note that it has
not been shown that constructing or interconnecting solar capacity at or near the Michoud site is
feasible. 687 They state that Mr. Movish’s review of ENO’s transmission studies indicates that
capacity, including solar capacity, must be constructed or otherwise interconnected at the
transmission level at or near the Michoud site to beneficially impact ENO’s NERC system
reliability standards compliance. 688 Mr. Movish has observed that it is not demonstrated in the
instant docket that such solar capacity can be constructed at or near the Michoud site; 689 and
WHEREAS, Advisors’ witness Mr. Movish concludes that the feasibility of solar or
wind capacity additions to deliver capacity where needed to resolve ENO’s potential NERC
system reliability violations (i.e., at or near the Michoud site) is unproven, the Council should
give particular consideration to the reality of the assumptions employed in modeling these
scenarios as discussed by Mr. Movish and Mr. Vumbaco and weigh the risk associated with
these against other alternatives presented. 690 The Advisors argue that the feasibility of wind
capacity to beneficially impact ENO’s NERC system reliability standards compliance is
undemonstrated because the interconnection of wind capacity at or near the Michoud site has not
been shown to be feasible. Mr. Movish notes that certain wind capacity discussed by Intervenors
has no transmission path to ENO and therefore would be ineffective in addressing ENO’s NERC
system reliability standards compliance; 691 and
WHEREAS, the Advisors do not find arguments that a competitive procurement process
or all-source RFP is required to be persuasive in the specific context of this case and under the

686

Advisors’ Post-Hearing Brief at 95, citing Vumbaco-1 at 6:18-20.
Advisors’ Post-Hearing Brief at 95, citing Vumbaco-1 at 22:4-11.
688
Advisors’ Post-Hearing Brief at 95, citing Vumbaco-1 at 22:4-11; Movish-1 at 31:15-32:3.
689
Advisors’ Post-Hearing Brief at 96, citing Vumbaco-1 at 22:4-11; Movish-1 at 32:6-8.
690
Advisors’ Post-Hearing Brief at 96, citing Vumbaco-1 at 26:20-27:4.
691
Advisors’ Post-Hearing Brief at 96, citing Vumbaco-1 at 22:15-20; Movish-1 at 33:22-34:12.
687

136

 specific circumstances of the need identified by ENO. 692 Dr. Stanton admits that at the time she
filed her testimony, she did not know how long it would take or what it would cost to conduct a
competitive procurement, or who would ultimately bear the cost of that. 693 She also admitted
that an IRP process has the potential to be another method of considering a full set of
alternatives. 694 In addition, the Advisors state that Joint Intervenors’ witness Mr. Henderson
testified that “[t]here may also be legitimate reasons a utility or utility regulator might determine
not to use a competitive procurement process in certain instances.

Small procurements,

procurements by small utilities, or procurements with very tight requirements, for example,
could warrant different treatment.” 695 While the Advisors would also generally prefer that ENO
use competitive solicitation processes to acquire resources in this case, the Advisors do believe
that the specific reliability needs identified in this case are “very tight requirements” due to the
specific geographic needs related to reliability and that there are a somewhat limited number of
resources that would be able to meet such requirements. Thus, the Advisors argue that a
competitive procurement process is not likely to produce substantially more options able to
mitigate the specific the reliability concerns than those options already identified by ENO; 696 and
WHEREAS, the Council disagrees with NOCS’ assertion that ENO can only
demonstrate that its decision-making was prudent and reasonable by showing that NOPS is the
least-cost option among alternatives. While the Council believes that in most cases, the leastcost option will indeed be the most prudent and reasonable option, economic factors are not the
only factors to be considered in determining the public interest. The Council believes that there

692

Advisors’ Post-Hearing Brief at 97.
Advisors’ Post-Hearing Brief at 97, citing Hr’g Tr. 12/21/17, 30:8-13.
694
Advisors’ Post-Hearing Brief at 97, citing Hr’g Tr. 12/21/17, 30:14-18.
695
Advisors’ Post-Hearing Brief at 97, citing Direct Testimony and Exhibits of Philip Henderson, Docket No. UD16-02, at 10:7-11 (Oct. 16, 2017) (“Henderson-1”).
696
Advisors’ Post-Hearing Brief at 98.
693

137

 are other factors that could reasonably cause a prudent utility to choose an option other than the
least cost option to address a particular need, such as quality of the technology, reliability
concerns, and environmental impacts; and
WHEREAS, the Council disagrees with NOCS’ assessment that ENO’s application is
fatally flawed because ENO failed to conduct an RFP when selecting the NOPS project; and
WHEREAS, the Council considers NOCS’ suggestion that the Council initiate a
rulemaking to develop RFP rules to be outside the scope of this proceeding, which was
established to consider ENO’s application for the NOPS Project; and
WHEREAS, the Council disagrees with the Joint Intervenors’ argument that without a
competitive solicitation process the Council cannot be assured that the price to be paid by
ratepayers is reasonable or fair. While the Council agrees that a competitive solicitation process
is one of the best methods of assessing what constitutes reasonable market prices for a project, it
is not the only means by which the reasonableness of the proposed costs can be assessed. The
Council retains its own independent experts with extensive experience in the field, and they have
reviewed the project costs and advised the Council that the costs are, in the Advisors’ opinion,
reasonable; 697 and
WHEREAS, the Council agrees with the Advisors that while it is generally preferable
that a new resource be subject to a competitive procurement process or all-source solicitation, in
the context of this case, the narrowly defined needs identified, specifically the need for a
dispatchable generation source at the Michoud site, indicate that a competitive procurement or
all-source solicitation would not be a prudent use of ratepayer resources because it would be
unlikely to yield significantly different options for the Council’s consideration, but would be
time consuming and expensive; and
697

Rogers-1 at 48:3-6.

138

 WHEREAS, the Council finds that given the significant doubts expressed by ENO and
the Advisors that the Transmission Alternative is feasible, requiring further exploration of that
option would not be a prudent use of ratepayer resources at this time; and
WHEREAS, the Council agrees that when considering ENO’s instant reliability needs,
relying on remote renewable resources, DSM, and battery storage to solve its reliability problems
is not the most prudent course of action. In light of that conclusion, the Council finds that ENO
has sufficiently explored those options; and
WHEREAS, the Council disagrees with the Joint Intervenors’ premise that prior
proceedings have prejudiced this proceeding. While the prior proceedings may have been one of
many factors encouraging ENO to explore the addition of a peaking resource in the City, all
Council directives to ENO made it clear that any specific resource acquisition proposed by the
Company would be subject to a full proceeding evaluating the merits of the proposal and
comparing it to other options for meeting the City’s electrical needs; 698 and
WHEREAS, the Council finds that the NOPS proposal, while not a direct result of the
2015 IRP analysis was significantly informed by that analysis. The Council notes that the
modification of ENO’s recommendations from the 2015 Final IRP to this proceeding primarily
reflected new data that was unavailable in the 2015 IRP proceeding. If the Council were bound
by the outcome of the AURORA modeling in the 2015 IRP case, then it would be required to
order ENO to build or acquire 250 MW of CCGT capacity, regardless of the reduced load
forecast that has occurred since the 2015 Final IRP indicating that such a large amount of
capacity is no longer projected to be needed. This outcome would not be in the public interest.
Indeed, if the position the Joint Intervenors take in this case were true, then neither the Council,
nor any other Commission could render decisions regarding the IRP processes of the utilities
698

Settlement Agreement at 13-14. Resolution No. R-15-524 at 12.

139

 they regulate without prejudicing every application for the acquisition of resources that utilities
subsequently filed; and
WHEREAS, the Council also notes that its decision not to make the outcome of the 2015
IRP binding on subsequent resource acquisitions was taken at the urging of the Alliance for
Affordable Energy who were not satisfied with the outcome of the 2015 IRP process and who
now as a member of the Joint Intervenors seeks to argue that the NOPS Application must be
rejected because it is not consistent with the 2015 Final IRP; and
WHEREAS, the Council rejects the argument that the Settlement Agreement regarding
the Entergy System Agreement Termination was conducted outside of public participation or that
it was entered into in a non-transparent manner.

As is explained above, that Settlement

Agreement was the subject of not one but two open, public proceedings, one at FERC and one
before the Council. The Joint Intervenors, having not participated in either proceeding, now seek
to make a collateral attack on the outcome of those proceedings. It is incumbent upon members
of the public who have an interest in energy matters to follow the proceedings of the Council and
other agencies that regulate such matters. The Council’s proceedings and the proceedings of
such other regulatory agencies are open to the public, and a party should not sit upon its rights
and then seek to undo the outcome after a proceeding has been completed. Regulators must be
able to issue decisions giving utilities guidance, and utilities must be able to rely upon that
guidance once the decisions have become final. To allow decisions to continually be undone
after the fact by parties who did not participate in the decision would result in regulatory chaos
that harms the public interest by impeding the utility’s ability to successfully conduct its
operations; and

140

 WHEREAS, the Council finds that through the over 21 community meetings, the
opportunity for any interested party to intervene and participate in this docket, including by
providing testimony in the case, the opportunity for members of the public to make formal
comments in the docket at the public hearing as well as the ongoing ability of the public to write
and contact their Councilmembers stating their opinion on the matter, the public has had
sufficient opportunity for input into the Council’s decision regarding ENO’s application; and
WHEREAS, as to the Joint Intervenors’ argument that the record in this case provides no
alternative explanation for the positions taken by ENO and the Advisors other than the
Settlement Agreement provision that ENO should examine building 120 MW of peaking
capacity in the City, the Council finds this argument to be incorrect on its face. The record
contains significant evidence that ENO bases its application on its assessment of the need for
capacity, its economic analysis of how to best fill that need, its assessment of its reliability needs,
and its engineering assessment of the various technologies available to it. Similarly, there is
substantial evidence in the record that the Advisors base their recommendation to the Council in
this docket on their own independent analysis of ENO’s application, testimony and discovery
responses and their conclusions regarding the capacity need, economic analysis and transmission
reliability analysis. Moreover, ENO and the Advisors do not take the same position in this case – ENO prefers the 226 MW CT and seeks Council approval of that option as its first choice,
while the Advisors reject the 226 MW CT and urge the Council to approve the 128 MW RICE
Alternative instead. The Joint Intervenors ignore the concerns articulated by both ENO and the
Advisors that the economic analysis showing that the Transmission Alternative is the least cost
alternative is not properly supported with a full analysis of the costs of that alternative and that
the Transmission Alternative would likely take several years longer to implement than either the

141

 CT Alternative or the RICE Alternative, leaving New Orleans ratepayers vulnerable to extensive
cascading outages of potentially long duration; and
WHEREAS, while the Joint Intervenors argue that the Council and the Advisors have
failed to take any action “to resolve the due process issues that arise from the prior agreement,”
the Joint Intervenors, none of whom participated in either the FERC proceeding or the Council
proceeding approving the Settlement Agreement make no suggestion as to what steps the
Council should take to undo the FERC decision in Entergy Arkansas, Inc., et al. 153 FERC
¶ 61,347 (2015) or the Council decision in Resolution No. R-15-524 approving the Settlement
Agreement. The Council finds that this argument is an impermissible collateral attack on a
FERC Order and a Council Resolution that the Joint Intervenors would like to now undo several
years after the fact after failing to exercise their rights to participate in those two dockets. The
Council finds that the Joint Intervenors have failed to prove that their due process rights have
been violated in this proceeding; and
WHEREAS, for the foregoing reasons, the Council finds that ENO has considered a
sufficient range of options to meet the identified need; and
III.

Whether ENO’s selection of the Michoud site is reasonable

WHEREAS, ENO argues that the record evidence confirms that the Michoud site is not
only reasonable, but ideal for the construction of NOPS for several reasons: (1) because of
ENO’s unique planning circumstances, adding capacity at the Michoud site provides the most
benefits to ENO’s customers, and of the two sites ENO owns in New Orleans, Michoud had
numerous advantages over the other site; (2) NOPS is not anticipated to have adverse effects
regarding groundwater or flooding; (3) the air emissions from NOPS will comply with all
applicable environmental regulations, which are designed to be protective of public health;

142

 (4) ENO has conducted extensive outreach to engage and inform the community regarding its
plans for NOPS; and (5) NOPS will not result in environmental injustice; 699 and
WHEREAS, ENO’s witness Mr. Jonathan Long offered the following summary of why
Michoud is the ideal site for NOPS:
[T]here are no residentially zoned properties or residences at the fence line
of this site, which is actually unusual in my experience in developing
plants in this region. This site has a number of things that are very
attractive about it. I understand from Mr. Charles Long that there’s a need
for power for reliability at this site. The infrastructure that is there in
terms of fuel supply, water supply, and transmission interconnection are
excellent. And, also, we’ve owned and operated on this site for at least 50
years and our knowledge of this site is also excellent, which is very much
a risk reducing factor. So as sites for new power plants go, all of those
things taken into account, this is an excellent site. 700
WHEREAS, ENO states that there are several unique planning circumstances that
indicate that the Company’s needs are best addressed with a plant located at the Michoud site:
(1) ENO is located at the far eastern end of the DSG load pocket, which is surrounded by water
on three sides and which is itself nestled inside the Amite South load pocket, thus making the
region highly reliant on local generation given the limited set of transmission lines to import
power from West to East; (2) there is no local generation in the City so ENO is 100% reliant on
transmission to serve its load; (3) generation is needed in an exact location, at the Michoud site,
to replace the retired Michoud units and accordingly mitigate a host of reliability concerns; and
(4) 100% of the Company’s load is inside MISO LRZ 9, while the vast majority of ENO’s
generation is located outside LRZ 9, which exposes customers to the potential for separation of
MISO capacity market prices; 701 and

699

ENO Post-Hearing Brief at 99.
ENO Post-Hearing Brief at 99, citing Hr’g Tr. 12/18/17, 127.
701
ENO Post-Hearing Brief at 100, citing Cureington-6 at 22-23, Cureington-8 at 8-12, 57.
700

143

 WHEREAS, ENO argues that the Michoud site had several advantages over the other
site owned by ENO in New Orleans, A.B. Paterson. ENO explains that Michoud is located close
to three major gas pipelines, has existing office building infrastructure, and has available bays in
the high-voltage switchyard for interconnection to the transmission system. In addition, and
most importantly, ENO argues, the Michoud site is more strongly interconnected to the
transmission system in the Company’s service area and the DSG load pocket than is the Paterson
Site, meaning that placing NOPS at Michoud would have many more positive effects on
transmission reliability in the DSG load pocket than other locations, including Paterson; and
WHEREAS, ENO argues that siting the plant at Michoud will have no adverse effects
regarding groundwater withdrawal or flooding, and that the evidence in the record includes
independent and industry-accepted analyses, which prove that neither the CT Alternative nor the
RICE Alternative will increase subsidence in New Orleans. 702

ENO witness Dr. George

Losonsky, a recognized expert in the scientific community with a Ph.D. in hydrology and over
30 years of experience in water resource risk management and problem solving testified as
follows:
My
independent
evaluation
involved
the
use
of
geotechnical/hydrogeological conceptual site models as well as drawdown
and consolidation calculations, the latter of which provides the Council
with a conservative, scientific quantification of the worst-case scenario of
the possible impacts of groundwater usage associated with NOPS for 50
years of operating the plant. These analyses are on par with, and in some
cases above and beyond, industry standards or any analysis if groundwater
usage impact assessments and they support my independent and sworn
representations to the Council that (i) neither of the proposed NOPS units
will increase or contribute to subsidence in New Orleans East or the
surrounding areas, (ii) neither unit will cause differential settlement, and
consequently, (iii) neither unit will pose any risk to the integrity of the

702

ENO Post-Hearing Brief at 101.

144

 area infrastructure, including the HSDRRS or other flood protection
infrastructure; 703
WHEREAS, ENO explains that in his worst-case scenario calculations, Dr. Losonsky
assumed that the units would be withdrawing the maximum amount of groundwater required for
operation 365 days per year and 24 hours per day, despite the fact that neither alternative would
operate at that frequency or withdraw water at that level, which, ENO explains, means his
calculations do provide a conservative, worst-case scenario prediction of risks. 704 ENO explains
his calculations are even more conservative because where, like at Michoud, groundwater
pumping has occurred for years, there is less potential for further consolidation and settlements,
but Dr. Losonsky assumed for the purposes of his calculations that there had been no prior
pumping at the site, so his calculations overstate the possible impacts of pumping, and still show
the worst-case possible impacts to be less than de minimis; 705 and
WHEREAS, ENO states that Dr. Losonsky is also a former Commissioner of the South
Louisiana Flood Protection Authority-East (“SLFPA-E”) and assisted the SLFPA-E in its efforts
to implement the Hurricane and Storm Damage Rick Reduction System (“HSDRRS”). 706 As
such, ENO argues, Dr. Losonsky is the only witness in the proceeding qualified to provide an
opinion on whether the proposed location and operation of NOPS creates any risks to the
integrity of the various HSDRRS measures and other similar flood protection infrastructure..707
Dr. Losonsky testified that he does not believe that siting and operating either NOPS alternative
would create any risk of damage to the integrity of the HSDRRS flood protection components or
nay other infrastructure in New Orleans East or the New Orleans metro area; 708 and

703

ENO Post-Hearing Brief at 101-102, citing Losonsky-2 at 20.
ENO Post-Hearing Brief at 102, citing Losonsky-1, Ex. GL-2 at 8, Losonsky-2 at 11.
705
ENO Post-Hearing Brief at 102-103, citing Losonsky-1 at 15-16, Losonsky-2 at 6.
706
ENO Post-Hearing Brief at 103-104, citing Losonsky-1 at 4-5, 23.
707
ENO Post-Hearing Brief at 104, citing Losonsky-2 at 19.
708
ENO Post-Hearing Brief at 104, citing Losonsky-2 at 19.
704

145

 WHEREAS, ENO argues that evidence in the record from multiple witnesses and
independent third parties demonstrates that siting NOPS as ENO has proposed would not subject
the unit to undue flood risks. 709 ENO argues that as ENO witness Mr. Jonathan Long testified,
design elevations for the proposed site and improvements to area flood protection infrastructure,
including the HSDRRS, serve to mitigate the factors that caused the site to experience flooding
due to the overtopping of levees during Hurricane Katrina. 710 As a result of the improvements,
ENO argues, the proposed NOPS site is extremely well-protected against the flood risks that
affect the entire Gulf Coast Region, as well as New Orleans specifically and that this, along with
many other factors, make the proposed site an ideal location for critical storm-response
infrastructure like NOPS; 711 and
WHEREAS, ENO argues that (1) the decommissioning and damming of the Mississippi
River Gulf Outlet; (2) the installation of the world’s largest surge barrier, the Lake Borgne Surge
Barrier; (3) the construction of St. Bernard Parish levee floodwalls on either side of the Lake
Borgne Surge Barrier; and (4) the completion of the Seabrook Floodgate on Lake Pontchartrain
surround the proposed NOPS site and will prevent the type of flooding that occurred at Michoud
during Katrina where water pushing up the Mississippi River Gulf Outlet into the Gulf
Intracoastal Waterway and a storm surge from Lake Pontchartrain also causing water to enter
into the Gulf Intracoastal Waterway caused the water in the Gulf Intracoastal Waterway to
overtop the levees at the Michoud site. 712

ENO also argues that the combination of these

improvements contributed to the Coastal Protection Restoration Authority’s (“CPRA”) 2017
Master Plan predicting no flooding at the proposed NOPS site under the worst case storm

709

ENO Post-Hearing Brief at 108.
ENO Post-Hearing Brief at 108, citing J. Long-3 at 19-20.
711
ENO Post-Hearing Brief at 108.
712
ENO Post-Hearing Brief at 109, citing J. Long-3 at 19-22, Ex. JEL-9.
710

146

 scenario modeled for the CPRA 2017 Master Plan during the 50-year assumed life of NOPS; 713
and
WHEREAS, ENO argues that in addition to the protections offered by the HSDRRS, the
NOPS project team took additional steps in the design and planning for NOPS to minimize the
risk of NOPS being impacted by flooding, because the Company uses a Top of Concrete
elevation in its design plans that exceeds FEMA guidance for the Michoud site in that it is 2.5
feet higher than the FEMA advisors recommendation. 714 ENO argues that it has demonstrated
that ENO is in compliance with the requirements of the City Council Ordinance No. 26906 715 on
flooding as well as all FEMA guidance, and all local regulations; 716 and
WHEREAS, ENO argues that its Risk & Insurance Management group arranged a tour
for the Company’s insurance underwriters and underwriters’ engineers of the proposed NOPS
site and the HSDRRS to allow them to evaluate the risk of issuing insurance for NOPS and to
demonstrate to the group that hurricane and storm damage risk associated with ENO’s portfolio
of assets had been gradually reduced by the installation of the HSDRRS system. 717 ENO states
that upon completion of the site visit and tour, the insurance underwriters conveyed to ENO’s
Risk & Insurance Management Group that, not only were they much more comfortable with
insuring ENO’s portfolio of assets, but they also felt that any flood risks to NOPS would be
minimal given HSDRRS and the fact that the Top of Concrete Elevation would be 3.5 feet above
sea level; 718 and

713

ENO Post-Hearing Brief at 109, citing Losonsky-2 at 11.
ENO Post-Hearing Brief at 111-113.
715
Council of the City of New Orleans, Ordinance No. 26906 (Apr. 7, 2016).
716
ENO Post-Hearing Brief at 112-113, citing J. Long-3 at 17-18 and Hr’g Tr. 12/20/17, 93-94.
717
ENO Post-Hearing Brief at 114-115, citing J. Long-3 at 18-19.
718
ENO Post-Hearing Brief at 115, citing J. Long-3 at 19.
714

147

 WHEREAS, ENO argues that with respect to air emissions, the evidence shows that
NOPS will be safe in every respect. 719 ENO notes that it must submit an application to the
LDEQ, and the LDEQ will perform an intense review of that application to ensure the plant
complies with all state and federal environmental standards and regulations and to ensure that the
plant will be operated safely without adverse health effects to the community. 720 ENO argues
that the permitted emissions of the plant will be significantly less than the permitted emissions of
the natural gas plant that operated at that same site for over 50 years, and that air dispersion
modeling performed in this proceeding by experts clearly demonstrates that there will be no
adverse health effects on the surrounding community as a result of air emissions from the new
facility. 721 ENO states that it will construct and operate NOPS safely and in accordance with all
applicable state and federal environmental regulations and without any adverse effects on the
health of Orleans Parish residents or anyone else; 722 and
WHEREAS, ENO argues that the LDEQ has been designated as the primary agency in
the state concerned with environmental protection and regulation, 723 and that the LDEQ is
charged with, inter alia, the regulation of air quality in Louisiana and ensuring compliance with
federal environmental legislation such as the CAA. 724

ENO explains that it must obtain a

preconstruction and operating permit from the LDEQ prior to beginning construction and that the
LDEQ will review ENO’s application submittal to assure that no adverse air quality impacts
would result from the project and identify all applicable state and federal regulations and
standards for the proposed equipment. 725 Therefore, ENO argues, before ENO can even begin

719

ENO Post-Hearing Brief at 115-116.
ENO Post-Hearing Brief at 116.
721
ENO Post-Hearing Brief at 116.
722
ENO Post-Hearing Brief at 116.
723
ENO Post-Hearing Brief at 116, citing La. Rev. Stat. § 30:2011 (2016).
724
ENO Post-Hearing Brief at 117.
725
ENO Post-Hearing Brief at 117.
720

148

 construction of NOPS, the LDEQ -- the state agency statutorily authorized and constitutionally
entrusted with the task -- will perform the preconstruction review and the review of all state and
federal air quality requirements that will apply to operation of the facility; 726 and
WHEREAS, ENO argues that as its air emissions and permitting expert witness Ms.
Higgins testified, each NOPS alternative will result in substantial decreases in permitted
(allowable) emission as compared to the currently permitted Michoud Power Plant. 727 ENO
testifies that the anticipated permitted emissions for each pollutant for the NOPS alternatives are
at least 48% below the corresponding permitted emissions for the former Michoud units, and in
several cases are over 95% lower than those permitted emissions; 728 and
WHEREAS, ENO argues that because Orleans Parish is in attainment with all of the
NAAQS, meaning air quality in the parish meets all federal air quality standards, only the CAA’s
New Source Review program (referred to as the Prevention of Significant Deterioration (“PSD”)
program) for attainment areas would apply to the NOPS alternatives. 729

This program is

designed to help ensure that states maintain compliance with the federal air quality standards and
prevent any deterioration of air quality in attainment areas. 730 ENO explains that under the PSD
regulations, each NOPS alternative would be considered a “minor modification” to the existing
stationary source (i.e., the Michoud plant) because the net emissions increase from each, when
combined with other creditable emissions increases and decreases occurring during a

726

ENO Post-Hearing Brief at 118.
ENO Post-Hearing Brief at 118, citing Higgins-1 at 17-19.
728
ENO Post-Hearing Brief at 118-120, citing Higgins-1 at 17-19.
729
ENO Post-Hearing Brief at 120-121, citing Higgins-1 at 21-22.
730
ENO Post-Hearing Brief at 121, citing Higgins-1 at 21-22.
727

149

 contemporaneous period, are below the level of emissions increases that the EPA has determined
to be de minimis with regard to their potential for adversely impacting air quality; 731 and
WHEREAS, ENO argues that because it is considered a “minor modification” and
therefore the level of increases are considered de minimis, ENO is not required to perform the air
quality analytics that would be required for a major modification to obtain a permit. 732 However,
ENO nevertheless retained emissions dispersion modeling experts from C-K Associates to
perform such modeling to further prove that air quality in the surrounding area would not be
adversely affected by the operation of NOPS; 733 and
WHEREAS, ENO argues that LDEQ assesses and incorporates into the draft permit
applicable emission control requirements, emission limitations, work practices, monitoring,
recordkeeping and reporting requirements based on the type of equipment, or activities proposed
and the level of potential emissions from the equipment and that minor modifications projects are
still subject to these requirements. 734 ENO explains the LDEQ (1) is responsible for reviewing
the emissions calculations, (2) establishes specific allowable mass emission rates through the
permitting process; (3) reviews the application with regard to pollutants not addressed by the
NAAQS; (4) may choose to perform dispersion modeling of the proposed emissions; and (5) has
broad authority to incorporate into the permit any conditions the agency deems reasonable and
necessary to protect air quality; 735 and

731

ENO Post-Hearing Brief at 121, citing Higgins-1 at 23, 27, Implementation of the New Source Review (“NSR”)
Program for Particulate Matter Less than 2.5 Micrometers (PM2.5), EPA, Final Rule, 73 Fed. Reg. 28,332 (May 16,
2008).
732
ENO Post-Hearing Brief at 121-122.
733
ENO Post-Hearing Brief at 122.
734
ENO Post-Hearing Brief at 122, citing Higgins-1 at 28-29.
735
ENO Post-Hearing Brief at 122-123, citing Higgins-1 at 28-29 and La. Admin. Code § 33:III.501.C.6.

150

 WHEREAS, ENO also argues that the air quality evaluation performed by C-K
Associates further proves that there will be no adverse impacts on air quality from NOPS.736
ENO explains that C-K Associates employed the EPA-preferred AERSCREEN air dispersion
model to perform screening analysis estimates of downwind ambient concentration of air
pollutants emitted from the CT and RICE Alternatives. 737 ENO reports that the AERSCREEN
modeling performed for the CT and RICE Alternatives revealed that the air emissions for the CT
and RICE Alternatives were well below the NAAQS for all modeled pollutants; 738 and
WHEREAS, ENO argues it has conducted extensive public outreach efforts and afforded
meaningful opportunity for public participation. 739 ENO states that during the 2015 IRP process
it hosted six public technical conferences and ran additional simulations and incorporated
stakeholder feedback and that the Council offered additional opportunities for public review and
comment on the 2015 Final IRP as well, with an additional technical conference, comments from
intervenors and a public hearing. 740 ENO also argues that after its initial NOPS filing, the
Council and ENO again provided multiple opportunities for public participation. 741 ENO met
with community groups, neighborhood associations, and other civic associations. 742 ENO states
that the Council ordered ENO to file supplemental testimony on environmental issues raised by
community members, with which ENO complied, provided an opportunity for Intervenors to file
testimony, ordered ENO to hold public hearings and held a hearing in its chambers. 743 ENO
states that it exceeded the Council’s order holding four meetings in New Orleans East with

736

ENO Post-Hearing Brief at 123, citing J. Long-3, Ex. JEL-6 at 15.
ENO Post-Hearing Brief at 123, citing J. Long-3, Ex. JEL-6 at 15.
738
ENO Post-Hearing Brief at 123-124, citing J. Long-3, Ex. JEL-6 at 15.
739
ENO Post-Hearing Brief at 128-129.
740
ENO Post-Hearing Brief at 129.
741
ENO Post-Hearing Brief at 129.
742
ENO Post-Hearing Brief at 129.
743
ENO Post-Hearing Brief at 129, citing Cureington-8 at 87.
737

151

 handouts in English, Spanish and Vietnamese. 744 ENO’s witness Mr. Cureington testified that
ENO has held at least 21 public meetings and Mr. Rice testified that he believes the number of
public hearings is closer to 30 and that he personally participated in nearly all of those
meetings; 745 and
WHEREAS, Air Products submits that the Michoud location is the only logical and
available choice for siting the NOPS unit. 746 Air Products explains that the Michoud site has the
necessary infrastructure, including the transmission interconnection that is critical to the
integration of any generation and that in proposing the site, ENO was complying with Resolution
No. R-15-524; 747 and
WHEREAS, NOCS states that the siting of any new facility was not the focus of its
review of the issues in this proceeding, but should the Council approve the RICE Alternative,
ENO’s Michoud site appears to be reasonable for its location. 748

NOCS explains that the

Michoud site appears to possess sufficient space and necessary transmission interconnection
facilities; 749 and
WHEREAS, the Joint Intervenors argue that the selection of the Michoud site is
unreasonable for the operation of a proposed gas-fired plant for the following reasons: (1) New
Orleans residents would suffer from the massive amounts of harmful air pollution released by the
proposed gas plants; (2) new flood control infrastructure protecting New Orleans East and Ninth
Ward that is next to the Michoud site would have the added risk of being weakened by
accelerated land subsidence caused by groundwater withdrawals for the proposed gas plant

744

ENO Post-Hearing Brief at 129-130, citing Cureington-8 at88.
ENO Post-Hearing Brief at 130, citing Cureington-8 at 89-90, Hr’g Tr. 12/20/17, 131.
746
Air Products Post-Hearing Brief at 14.
747
ENO Post-Hearing Brief at 14-15, citing Lovorn-1 at 8:14-19.
748
NOCS Post-Hearing Brief at 26.
749
NOCS Post-Hearing Brief at 26.
745

152

 options; (3) the proposed gas pants would each create racially disproportionate pollution and
flood risk burdens on nearby African American and Vietnamese American neighborhoods, which
have been disregarded by ENO; (4) FEMA has determined that the location chosen on the
Michoud site for the proposed gas plants has a high incidence of flood events, and cautions
against building new power plants in such locations; (5) ENO has developed a deeply flawed
design for the proposed gas plants that completely fails to ensure compliance with the City of
New Orleans Flood Damage Prevention Ordinance as well as FEMA policy and standards
applicable to new construction of power plants; and (6) ENO only considered Michoud and A.J.
Paterson as potential sites for a proposed gas plant, and did not consider other sites as directed by
Council Resolution No. R-15-524; 750 and
WHEREAS, the Joint Intervenors argue that each of ENO’s proposed gas-fired
generation options would create racially disproportionate environmental burdens on
predominately African American and Vietnamese neighborhoods in New Orleans East. 751 They
allege that each would annually release significant amounts of air pollution near homes and
schools and that the CT Alternative would also create significant flood risks that can impact the
same surrounding neighborhoods which have yet to fully recover from the levee failure during
Hurricane Katrina; 752 and
WHEREAS, the Joint Intervenors state that their witness, Dr. Wright, analyzed the 1950
U.S. Census data, which indicates a plan to operate the Michoud power plant in a remote
location in New Orleans East that was away from neighborhoods and at that time, New Orleans
East was mostly undeveloped with a sparse population of approximately 8,000 people. 753 The

750

Joint Intervenors’ Post-Hearing Brief at 103.
Joint Intervenors’ Post-Hearing Brief at 68.
752
Joint Intervenors’ Post-Hearing Brief at 68.
753
Joint Intervenors’ Post-Hearing Brief at 68, 80-81, citing Wright-1 at 13:7-15.
751

153

 Joint Intervenors argue that the 2010 Census data reflect the population growth in New Orleans
East, which is now home to approximately 64,000 people, of whom 84% are African American
and 8% are Vietnamese American. 754 The Joint Intervenors also argue that the population of
New Orleans East has grown with residential developments extending to a distance that is less
than one mile from the Michoud site boundary; 755 and
WHEREAS, the Joint Intervenors claim that ENO provided a false statement in its
2004Environmental Assessment Statement to the LDEQ that there are no homes or schools in the
vicinity of the Michoud site. 756 The Joint Intervenors argue that for years, ENO has operated the
Michoud power plant in complete disregard of its racially disproportionate environmental
burdens on predominately African-American and Vietnamese-American residents; 757 and
WHEREAS, the Joint Intervenors argue that in its application, ENO does not examine,
or even consider, the racially-disproportionate environmental burdens of operating a power plant
in close geographic proximity to predominately African-American and Vietnamese-American
neighborhoods. 758 The Joint Intervenors take issue with ENO’s representation that “no people
live within a one mile radius of the center of the Michoud site “because ENO measures from the
center of the Michoud site rather than from the perimeter.” 759 The Joint Intervenors argue that
ENO should have used a three-mile radius, which they argue is typically used for environmental
justice analysis of polluting facilities that are nearby populations; 760 and
WHEREAS, the Joint Intervenors argue that ENO’s pollution estimates have not been
confirmed by the LDEQ and do not include the amounts of sulfuric acid mist that would be

754

Joint Intervenors’ Post-Hearing Brief at 68, 81, citing Wright-1 at 13:11-14:1.
Joint Intervenors’ Post-Hearing Brief at 68.
756
Joint Intervenors’ Post Hearing Brief at 69, citing Wright-2 at 7-8 and Ex. 1.
757
Joint Intervenors’ Post-Hearing Brief at 69.
758
Joint Intervenors’ Post-Hearing Brief at 69.
759
Joint Intervenors’ Post-Hearing Brief at 69.
760
Joint Intervenors’ Post-Hearing Brief at 69.
755

154

 released into the air or the types and amounts of toxins that would be discharged as water
pollution, but that nevertheless ENO’s pollution estimates do indicate that ambient air quality
will worsen with the air pollution from NOPS; 761 and
WHEREAS, the Joint Intervenors argue that it is insufficient for ENO to obtain the
required permits to release air pollution because the Council directed ENO to address “the air
quality effects of the proposed New Orleans Power Station,” and obtaining air permits to release
pollution will cause air quality to worsen. 762 The Joint Intervenors argue that the effects of poor
air quality across Louisiana arise from permitted air pollution, and that ENO’s expert witness
Higgins, a former LDEQ employee, acknowledged that her previous approvals of air permits
issued to major industrial facilities operating in Louisiana’s infamous Cancer Alley; 763 and
WHEREAS, the Joint Intervenors argue that their witness, Dr. Thurston, is the only
witness to address the health effects of air pollution and that air pollution causes cancer and
impaired respiratory and cardiovascular function. 764

The Joint Intervenors argue that Dr.

Thurston’s testimony shows that air pollution from sources like power plants is associated with
serious adverse human health effects. 765 The Joint Intervenors argue that the health effects of
permitted air pollution released by power plants lays bare the reality recognized by Louisiana
courts that “a regulatory standard and a guarantee of safety are not synonymous;” 766 and
WHEREAS, the Joint Intervenors argue that ENO’s assertion that either NOPS
alternative will meet minimum federal standards is not going to be much comfort to the residents
who actually have to breathe pollution from the plant, and that it is incorrect because the

761

Joint Intervenors’ Post-Hearing Brief at 70, citing Higgins-1 at 18-19.
Joint Intervenors’ Post-Hearing Brief at 70, citing Resolution No. R-16-506.
763
Joint Intervenors’ Post-Hearing Brief at 70-71, citing Hr’g Tr. 12/19/17, 64:2-5.
764
Joint Intervenors’ Post-Hearing Brief at 71, 77-79, citing Thurston-1 at 5-8, Thurston-2 at 8.
765
Joint Intervenors’ Post-Hearing Brief at 77, citing Thurston-1 at 3.
766
Joint Intervenors’ Post-Hearing Brief at 71, citing Johnson v. Orleans Parish School Board, 975 So. 2d 678, 711
(La. App. 4th Cir. 2008).
762

155

 pollutants will exceed the EPA PSD levels at which increased pollution from an existing
stationary source in an attainment area would trigger specific requirements for emissions control
and analysis; 767 and
WHEREAS, the Joint Intervenors argue that the poor are especially at risk from air
pollution, and older adults and children are also at greater risk; 768 and
WHEREAS, the Joint Intervenors argue that there are two known characteristics of
natural gas-fired power plant particulate matter that make them likely to have especially strong
adverse health effects, on a per-pound basis: they have a higher percentage of ultrafine particles
as compared to PM from other fossil fuel sources and they contain a high percentage of toxic
transition metals; 769and
WHEREAS, the Joint Intervenors argue that ENO’s response that as a technical matter
the gas plant can avoid more stringent review and will meet the minimum air quality standards
set by the EPA ignores the fact EPA’s standards do not remove the risk to neighbors of the
plant; 770 and
WHEREAS, the Joint Intervenors argue that rather than being a part of a regulatory
framework designed to protect people from the harms associated with pollution emissions, the
EPA distinction between a major or minor modification is simply a regulatory construct designed
for administrative ease in determining the baseline that triggers certain kinds of review when a
permit is issued. 771 They also argue that the CAA’s ambient air quality standards also focus on
maintaining region-wide air quality, not on addressing pollution impact to specific communities

767

Joint Intervenors’ Post-Hearing Brief at 76-77.
Joint Intervenors’ Post-Hearing Brief at 79, citing Thurston-1 at 25.
769
Joint Intervenors’ Post-Hearing Brief at 79-80, citing Thurston-1 at 28.
770
Joint Intervenors’ Post-Hearing Brief at 80.
771
Joint Intervenors’ Post-Hearing Brief at 80.
768

156

 near a plant’s fence line like those in New Orleans East. 772 The Joint Intervenors argue that to
protect the public interest, the Council should adopt a “baseline” level to judge proposed projects’
effect on New Orleans East that reflects existing physical conditions. 773 They argue that as a
result of ENO’s decision to close the old Michoud units in 2016, there are no power-plant
emissions from the Michoud site and that the proposed projects will result in substantial
increases in pollution emissions from the current status quo; 774 and
WHEREAS, the Joint Intervenors urge the Council to reject the assertion of ENO’s
consultant, C-K Associates, that emissions are dissipated before they reach the fence line to
concentrations much below the limits for public breathing level air because C-K Associates cites
no evidence or analysis for this conclusion and cannot support this claim because PM 2.5 can
travel hundreds or thousands of miles. 775 The Joint Intervenors argue that even if the emissions
dissipate at the fence line, the limits established by the NAAQS are not fully protective of public
health. 776 The Joint Intervenors argue that particularly in this instance where clean options such
as solar and energy efficiency are readily available, the Council should select that option that
preserves public health rather than the option which puts public health at greater risk of serious
disease and death; 777 and
WHEREAS, the Advisors argue that the Michoud site is a reasonable choice, given the
identified need; 778 and
WHEREAS, the Advisors argue that ENO has identified a specific need for generation
resources to be installed in the eastern part of the City in order to alleviate certain identified
772

Joint Intervenors’ Post-Hearing Brief at 80.
Joint Intervenors’ Post-Hearing Brief at 80.
774
Joint Intervenors’ Post-Hearing Brief at 80.
775
Joint Intervenors’ Post-Hearing Brief at 81, citing J. Long-2, Ex. JEL-6 at 16, Catawba County, North Carolina v.
EPA, 571 F.3d 20, 26 (D.C. Cir. 2009).
776
Joint Intervenors’ Post-Hearing Brief at 81-82.
777
Joint Intervenors’ Post-Hearing Brief at 81.
778
Advisors’ Post-Hearing Brief at 98.
773

157

 transmission problems and that installing generation to the west would not sufficiently mitigate
the need. 779 The Advisors argue that because such a large amount of generation (781 MW of
capacity) around which the ENO system had been designed, putting some level of generation
back at or near that location will help support the system in a manner that putting generation in
other locations will not; 780 and
WHEREAS, Advisors’ witness Mr. Movish testified that locating local generation at
Michoud would have a direct transmission path to eliminate the transmission overloads that
would result in the event of the P6 contingency and support ENO’s ability to continue to reliably
serve its customers. 781 Mr. Movish also opines that the alternate location of local generation,
such as in the western portion of ENO’s system would not support ENO’s ability to reliably
serve its load and mitigate transmission reliability violations because the occurrence of a P6
contingency would sever the interface between ENO’s 115 kV and 230 kV networks, thereby
eliminating the transmission path needed to mitigate it, and as a result, such generation would
not support ENO’s ability to continue to serve its customer loads; 782 and
WHEREAS, the Advisors argue that to the extent that generation is to be sited in the
eastern part of the City in order to maintain reliability, the Michoud site has several advantages
that benefit ENO customers, including customers in New Orleans East: (1) ENO already owns
the property, saving ratepayers the expense of acquiring it; (2) it already has a significant amount
of necessary infrastructure in place, including gas pipeline and transmission and distribution
lines running into the site, and administrative building facilities that will result in substantial cost
savings; (3) ENO already has several permits applicable to the site that allow it to streamline the
779
Advisors’ Post-Hearing Brief at 98, citing Cureington-5 at 21:3-22:5, Movish-1 at 25:3-9, and C. Long-3 at
16:16-17:4.
780
Advisors’ Post-Hearing Brief at 98-99, citing Rice-1 at 3:7-8.
781
Movish-1 at 24:17-20.
782
Movish-1 at 25:39.

158

 permitting process; and (4) it is in a sparsely populated, industrial area where a plant had
previously operated successfully for decades; 783 and
WHEREAS, the Advisors note that there are also other positive impacts on the
community of constructing NOPS – ENO submitted an economic analysis demonstrating that
either Alternative would produce hundreds of millions of dollars in economic benefits in the
form of new business sales, new household earnings, new permanent jobs and new tax
collections, both from construction and operation. 784 The Advisors argue that the economic
study demonstrated that the RICE Alternative would provide even greater benefits than the CT
Alternative from ongoing operational expenditures that will continue to accrue for as long as
NOPS is in operation; 785 and
WHEREAS, the Advisors assert that the C-K Report submitted by ENO along with the
testimony of Dr. Losonsky and the CB&I Report, demonstrated that the proposed units will not
contribute to additional subsidence at Michoud and that flood risks have been substantially
mitigated. 786

The Advisors found that the authors of the two reports performed extensive

analysis and demonstrated that the proposed groundwater withdrawals for the CT Alternative and
RICE Alternative would be too small to contribute to any subsidence in the Michoud area; 787 and
WHEREAS, the Advisors note that when compared to the deactivated Michoud units,
the alternative recommended by the Advisors, the RICE Alternative, usage rate will result in a
99.9% reduction in groundwater use. 788 The Advisors are persuaded by this evidence and find it

783

Advisors’ Post-Hearing Brief at 99, citing J. Long at 41:21-42:10, Rice-4 at 16:10-12.
Advisors’ Post-Hearing Brief at 99, citing Rice-4 at 18:9-19:5, Ex. CLR-3.
785
Advisors’ Post-Hearing Brief at 99, citing Rice-4 at 18:9-19:5, Ex. CLR-3.
786
Advisors’ Post-Hearing Brief at 100-108.
787
Advisors’ Post-Hearing Brief at 100-101, citing Losonsky-1 at 8:12-14, 17:19-22, Ex. GL-3, J. Long-3, Ex. JEL6 at 1.
788
Advisors’ Post-Hearing Brief at 102, citing Losonsky-1, Ex. GL-2 at 2.
784

159

 noteworthy that these calculations were performed using the most conservative assumption that
the RICE Alternative would operate 24 hours per day, 365 days per year; 789 and
WHEREAS, the Advisors are not persuaded by the testimony of Joint Intervenors’
witness Dr. Kolker, finding that he did not provide any analysis containing his own calculations
or site-specific information to support his positions, but that he merely relied upon the research
of others, which did not include any specific analysis or drawdown calculations. 790

The

Advisors note that Dr. Kolker acknowledged that prior to this case, he had never attempted to
assess possible subsidence resulting from groundwater withdrawal from a specifically proposed
industrial facility; 791 and
WHEREAS, the Advisors find it persuasive that ENO has presented evidence that the
flood protection measures, including the HSDRRS, that have been installed eliminate estimated
flooding at the Michoud location even under the worst case scenario considered under the
CPRA’s 2017 Master Plan; 792 and
WHEREAS, the Advisors are also persuaded by ENO’s evidence that, in addition to the
flood protection measures being taken by the SLFPA-E, ENO has determined the appropriate
Top of Concrete level to be 3.5 feet above sea level, which is 2.5 feet higher than the FEMA
Advisory recommendation and one foot higher than the observed Hurricane Katrina flooding; 793
and
WHEREAS, the Advisors observe that while Dr. Wright argues that ENO’s proposal
will have a racially discriminatory effect because ENO established a deeply flawed planning
process without public input, evaluated sites in disregard to population growth and applied for
789

Advisors’ Post-Hearing Brief at 105.
Advisors’ Post-Hearing Brief at 105.
791
Advisors’ Post-Hearing Brief at 106, citing Hr’g Tr. 12/201/7, 140:3-8.
792
Advisors’ Post-Hearing Brief at 106-107, citing Losonsky-1 at 25:4-9.
793
Advisors’ Post-Hearing Brief at 107, citing Losonsky-1 at 24:4-9.
790

160

 and/or obtained environmental permits that do not require public notice, Dr. Wright has no
background, education, or experience in energy resource planning or power plant siting or
permitting. 794 The Advisors note that she does not appear to have any relevant experience in
utility resource planning, utility transmission or generation planning or operations, or electrical
engineering that would assist her in evaluating and understanding the decision to put a power
plant in a specific location. 795 The Advisors conclude that Dr. Wright and the other Joint
Intervenors’ witnesses have simply failed to provide sufficient evidence to demonstrate that the
siting of a natural gas-fired power plant at the Michoud site will perpetuate environmental
racism; 796 and
WHEREAS, the Advisors argue that ENO has presented as a witness Bliss Higgins, an
experienced former Assistant Secretary of the LDEQ’s Office of Environmental Services and
recognized air quality expert, who over the course of her work at LDEQ and later as an
environmental consultant, has studied the EPA’s guidelines on environmental justice, and
conducted evaluations to assess whether particular projects would result in a disproportionate
adverse impact on minority or low-income populations. The Advisors note that Ms. Higgins
testified that, based on the specific facts and circumstances of the proposed NOPS alternatives,
the applicable science, and well-established environmental standards, it is her opinion that the
operation of NOPS will not result in any environmental injustice for the following reasons:
(1) Orleans Parish is currently in attainment of NAAQS; (2) the project will be cited more than
one mile from the nearest residential area; and (3) the objective data support the conclusion that
there will be no significant adverse health impacts from NOPS; 797 and

794

Advisors’ Post-Hearing Brief at 108, citing Wright-1 at 21:4-22:19 and Ex. 1.
Advisors’ Post-Hearing Brief at 109, citing Wright-1, Ex. 1.
796
Advisors’ Post-Hearing Brief at 109.
797
Advisors’ Post-Hearing Brief at 109-110, citing Higgins-1 at 6:4-9:3; see also, ENO-2 at 8:6-9:9, 17:5-10.
795

161

 WHEREAS, the Advisors recommend that the Council rely upon the determinations of
the EPA and LDEQ as to whether there will be an adverse health impact, and that if they
determine no adverse health impact, then there would not be a racially disproportionate
significant adverse health impact. 798 The Advisors note that ENO witness Mr. Rice committed
that the air emissions from NOPS will not exceed regulatory standards that have been put in
place to safeguard human health and the environment and will be less than the retired Michoud
units; 799 and
WHEREAS, the Advisors conclude that the Joint Intervenors have failed (1) to offer any
evidence that effectively counters ENO’s evidence that the proposed plant will meet all
applicable regulatory requirements regarding emissions, and (2) to demonstrate that there will be
any significant adverse health impacts from siting the plant at Michoud. 800 The Advisors also
argue that Louisiana case law regarding environmental justice does not support a finding that
environmental discrimination would be perpetuated by the siting of a natural gas plant at
Michoud. 801 The Advisors argue that the case of North Baton Rouge Environmental Association
v. Louisiana Department of Environmental Quality is particularly instructive. In that case, the
court found that in a situation where a plant was being built at the same site where a plant
previously stood, where that previous plant had polluted more, and was in an industrial area
where there was no indication that the original zoning was intentionally racist, the granting of a
permit did not constitute environmental racism solely due to the proximity of an African
American neighborhood; 802 and

798

Advisors’ Post-Hearing Brief at 111.
Advisors’ Post-Hearing Brief at 111, citing Rice-4 at 21:10-15.
800
Advisors’ Post-Hearing Brief at 111.
801
Advisors’ Post-Hearing Brief at 111.
802
Advisors’ Post-Hearing Brief at 111-114, citing N. Baton Rouge Envtl. Ass’n v. La. Dep’t of Envtl. Quality, 805
So. 2d 255, 263 (La. App. 1st Cir. 2001).
799

162

 WHEREAS, the Advisors believe that this case compares favorably to North Baton
Rouge, in that Orleans Parish is already in attainment with all NAAQS whereas the area at issue
in that case was not, the Michoud site is a sparsely populated industrial site where a power plant
has been operating for decades, and, based on expert testimony, the proposed RICE unit will
represent a significant reduction in allowable emissions compared to the allowable emissions
from the deactivated Michoud units. 803 Moreover, the Advisors note, the appellants in the North
Baton Rouge case argued that the initial siting of the facility was racially discriminatory, whereas
in this case, even Dr. Wright admits in her testimony that when the original Michoud plant was
undertaken, New Orleans East was largely undeveloped wetlands and sparsely populated; 804 and
WHEREAS, the Advisors note that ENO has submitted expert testimony indicating that
the emissions from the RICE units would be dissipated before they reach the fence line to
concentrations well below the limits for public breathing level air based on federal air quality
standards, and the emissions represent an average 77.3% reduction in criteria pollutants pursuant
to the EPA’s air quality standards compared to the two old Michoud units retired in 2016; 805 and
WHEREAS, the Advisors believe that the remainder of Dr. Wright’s claims also fall
apart under further examination. 806 The Advisors do not find Dr. Wright’s claims that the 2015
IRP Process was highly flawed, because there was no mention of the siting of the proposed CT
discussed in that proceeding to be persuasive because it seems to be based on a misunderstanding
of what an IRP process is and does. 807 The Advisors note that an IRP proceeding simply does
not consider the location of any specific resource that may be acquired in the future; 808 and

803

Advisors’ Post-Hearing Brief at 114; see also, ENO-2 at 15:6-8.
Advisors’ Post-Hearing Brief at 114, citing Wright 1 at 13:7-14:8.
805
Advisors’ Post-Hearing Brief at 114, citing Higgins-1 at 50:1-7, 11-15.
806
Advisors’ Post-Hearing Brief at 114.
807
Advisors’ Post-Hearing Brief at 115.
808
Advisors’ Post-Hearing Brief at 115-116.
804

163

 WHEREAS, the Advisors also argue that the Company’s 2015 IRP process and its
specific proposal to construct NOPS have provided multiple opportunities for meaningful public
participation, with at least 21 public meetings regarding NOPS, the opportunities provided by
Council Resolution Nos. R-16-506 and R-17-426 for interested parties and the public at large to
be heard regarding the NOPS proposal including public outreach meetings in each Council
district and a public hearing in the Council chambers. 809 The Advisors argue that any member of
the public who took the time to follow the Council’s energy-related proceedings would have
been aware that although the type of technology and specific location were not determined until
ENO filed its application in this docket, the potential siting of a power plant in New Orleans has
been under discussion before the Council since at least 2015, beginning with the proposed
settlement regarding the termination of the Entergy System Agreement, and continuing through
the 2015 IRP process and into the instant docket, with ample notice and opportunity for public
input in each docket; 810 and
WHEREAS, the Advisors find the testimony of Ms. Higgins regarding the proximity of
residential neighborhoods to the Michoud site to be more persuasive than the testimony of Dr.
Wright, due to Ms. Higgins’ use of the tool preferred by the EPA; 811 and
WHEREAS, the Advisors also find no merit in Dr. Wright’s argument that ENO’s
process perpetuated environmental racism because it applied for and/or obtained environmental
permits that do not require public notice, public comments, or public hearing. 812 The Advisors
argue that to the extent ENO applied for environmental permits in a manner that meets the

809

Advisors’ Post-Hearing Brief at 116.
Advisors’ Post-Hearing Brief at 117-121.
811
Advisors’ Post-Hearing Brief at 122-124.
812
Advisors’ Post-Hearing Brief at 124.
810

164

 requirements of the EPA and LDEQ, the Advisors see no reason for the Council to conclude that
applying for such permits reflects discriminatory intent on the part of ENO; 813 and
WHEREAS, the Advisors argue that to the extent that Dr. Wright does not feel that the
EPA and LDEQ processes permit sufficient public input, she should raise that matter before the
EPA and LDEQ; 814 and
WHEREAS, the Advisors conclude that siting a power plant at Michoud under the
circumstances described by ENO in its Initial Application, Supplemental Application, and
testimony is reasonable and in the public interest, particularly in light of ENO’s commitment to
comply with all applicable local, state, and federal laws and regulations. 815

The Advisors

recommend that the Council require ENO to submit proof of such compliance in the form of
submitting to the Council copies of all permits and authorizations received by the Company; 816
and
WHEREAS, ENO argues that no party has presented evidence of any risks associated
with the specific groundwater usage required to operate NOPS, and no party has presented any
scientifically-based challenges to the calculations Dr. Losonsky performed to prove that NOPS
will not increase subsidence and that NOPS poses no risk to area infrastructure, including the
flood protection measures that Dr. Losonsky helped to design and implement as a Commissioner
of the SLFPA-E; 817 and
WHEREAS, ENO argues that Joint Intervenors’ witness Dr. Kolker has a Ph.D. in
“Marine and Atmospheric Science” but does not have any degrees in geology or hydrogeology,
and several of his admissions and omissions demonstrate that he has no basis for disputing the
813

Advisors’ Post-Hearing Brief at 124.
Advisors’ Post-Hearing Brief at 124-125.
815
Advisors’ Post-Hearing Brief at 125.
816
Advisors’ Post-Hearing Brief at 125.
817
ENO Post-Hearing Brief at 116-117.
814

165

 accuracy of Dr. Losonsky’s calculations and the resulting conclusions. 818 ENO argues that Dr.
Kolker admitted that, prior to this proceeding, he has never before attempted to assess potential
impacts of groundwater withdrawal or to assess possible subsidence risks, related to an industrial
facility. 819 ENO argues that Dr. Kolker admitted that, unlike Dr. Losonsky, he did not perform
any drawdown or consolidation calculations and made no attempt to replicate Dr. Losonsky’s
calculations or verify the accuracy of his results; 820 and
WHEREAS, ENO argues that Dr. Kolker’s criticism that Dr. Losonsky’s calculations
only covered a 10-year period is demonstrably false because Dr. Losonsky’s calculations
covered a 50-year period. 821 ENO also argues that Dr. Kolker’s criticism that that Dr. Losonsky
failed to explain what happens to void space left by pumping demonstrates his fundamental lack
of understanding of aquifer hydraulics and drawdown and consolidation calculations, because Dr.
Losonsky’s calculations demonstrated that no void space would be created. 822 ENO states that
beyond his limited and erroneous attempts to cast doubt on Dr. Losonsky’s analysis, Dr.
Kolker’s discussion of subsidence is focused on his recommendation that the Council obtain
another opinion on subsidence beyond that provided by Dr. Losonsky, despite the fact that Dr.
Losonsky’s analysis provided the level of detail that Dr. Kolker recommends. 823 ENO argues
that neither Dr. Kolker nor any other Joint Intervenors’ witness has provided any evidence or
analysis specific to NOPS that in any way substantiates the claims that NOPS poses a
subsidence-related risk to New Orleans, while Dr. Losonsky’s undisputed, scientifically-valid

818

ENO Post-Hearing Brief at 105, citing Kolker-1, Ex. AK-1, and Kolker-2 at 1.
ENO Post-Hearing Brief at 105, citing Hr’g Tr. 12/20/17, 139-140.
820
ENO Post-Hearing Brief at 105, citing Hr’g Tr. 12/20/17, 144-146, 153.
821
ENO Post-Hearing Brief at 106, citing Kolker-2 at 5, Losonsky-2 at 7-11.
822
ENO Post-Hearing Brief at 106, citing Kolker-2 at 4, Losonsky-1, Ex. GL-2 at 3, Losonsky-2 at 11.
823
ENO Post-Hearing Brief at 107, citing Kolker-1 at 10.
819

166

 calculations affirmatively demonstrate that no such risk exists, even in a worst-case scenario; 824
and
WHEREAS, ENO observes that with respect to flooding at the Michoud site, Dr. Kolker
refers to the outdated 2012 CPRA Master Plan’s assessment of flood risks at the Michoud site,
which did not take into account the HSDRRS measures and other improvements, and that Dr.
Kolker ignores the 2017 CPRA Master Plan’s assessment that there is no flood risk under the
same scenario. 825 ENO argues that Dr. Kolker admitted that the post-Katrina flood protection
systems are substantially better than the pre-Katrina ones; 826 and
WHEREAS, ENO also argues that Dr. Kolker’s assessment of the flood risks at the
Michoud site overlooked ENO’s plan to raise the elevation of the proposed location of the NOPS
units by 5.5 feet and that Dr. Kolker’s predictions did not appear to be granular enough to
provide site-specific risk evaluations for the NOPS site. 827 ENO argues that Dr. Kolker further
admitted that his assessment of flood risks assumed current conditions at the time of the study
and did not take into account the proposed elevation changes and that Dr. Kolker admitted he has
never previously attempted to assess possible flood risks associated with a proposed industrial
facility; 828 and
WHEREAS, ENO argues that the Joint Intervenors’ assertions regarding air emissions
are contradicted by the evidence. 829 ENO argues that without any specific evidence with regard
to NOPS, the Joint Intervenors have attempted to sow fear in the community despite the fact that
their allegations lack any factual or evidentiary support. 830 ENO argues that the only testimony

824

ENO Post-Hearing Brief at 107-108.
ENO Post-Hearing Brief at 109-110, citing Kolker-1 at 7-9.
826
ENO Post-Hearing Brief at 110, citing Hr’g Tr. 12/20/17, 162-163.
827
ENO Post-Hearing Brief at 113-114, citing Hr’g Tr. 12/20/17, 164-165.
828
ENO Post-Hearing Brief at 113-114, citing Hr’g Tr. 12/20/17, 141, 164-165.
829
ENO Post-Hearing Brief at 124-125.
830
ENO Post-Hearing Brief at 125.
825

167

 they have submitted on the issue of air emissions addresses only PM 2.5 emissions, and only in a
general sense, without any attempt to specifically address NOPS. 831 ENO argues that Joint
Intervenors have not submitted any testimony that attempts to refute the C-K Technical Report or
the air emissions conclusions contained therein, neither have they attempted to conduct their own
analysis or air dispersion modeling. 832 ENO also notes that Joint Intervenors have not taken
exception to ENO’s conclusion that NOPS will be considered a minor modification under the
PSD program, rather at trial, counsel for the Alliance appeared to try to get ENO’s expert, Ms.
Higgins, to concede that the statutory framework established for the PSD program is based on a
“regulatory fiction” in that it allows the decrease in currently-permitted emissions from the
Michoud plant to be netted against the NOPS emissions for the purpose of determining potential
effects on air quality from the new facility. 833 ENO also argues that counsel for the Alliance
proceeded to suggest that the Council simply ignore the legal and regulatory framework
established by Congress, the EPA, the Louisiana legislature and the LDEQ and draw its own
conclusions regarding air emissions; 834 and
WHEREAS, ENO argues that the Joint Intervenors would have the Council usurp the
role of the LDEQ, disregard the legal and regulatory framework on air emissions, and ignore the
federally imposed air emissions standards that have been developed through a public process
over the course of several years and with extensive input from the public and scientific
community and instead impose its own air emissions standards and regulations without
undergoing any process; 835 and

831

ENO Post-Hearing Brief at 125-126.
ENO Post-Hearing Brief at 126.
833
ENO Post-Hearing Brief at 126.
834
ENO Post-Hearing Brief at 127.
835
ENO Post-Hearing Brief at 127.
832

168

 WHEREAS, ENO argues that the Joint Intervenors would have the Council tell the only
Fortune 500 Company headquartered in the City that it cannot invest over $200 million in the
community to build a modern, efficient peaking generation power plant that ENO’s transmission
engineers have sworn under oath is needed to prevent cascading outages in the City in the near
future, and that such denial could be based on the simple fact that the plant will have emissions
associated with burning natural gas to create electricity, even though the air emissions will be
significantly lower than the previous plant and are by law considered de minimis. 836 ENO argues
that this would be bad public policy and send an extremely poor signal to other businesses that
might be considering investing in New Orleans by locating operations in the City; 837 and
WHEREAS, ENO disagrees with Dr. Wright’s criticism of ENO for applying to LDEQ
for a minor modification of the existing Michoud air permit that does not require public
comment or an Environmental Assessment Statement and states that the Company’s application
was entirely proper and that the LDEQ set public hearings in New Orleans East when the
application was initially filed, which were cancelled due to various circumstances, but that the
LDEQ had invited and received public comments and has indicated that it intends to schedule a
new public hearing on any draft permits that would authorize the construction and operation of
NOPS; 838 and
WHEREAS, ENO also argues that siting NOPS at Michoud does not raise any
environmental justice concerns. 839

ENO argues that environmental justice is generally a

consideration of whether minority and low-income populations are being disproportionately

836

ENO Post-Hearing Brief at 127-128.
ENO Post-Hearing Brief at 128.
838
ENO Post-Hearing Brief at 130-131, citing Hr’g Tr. 12/191/7, 77-78. See also, ENO-2 at 18.
839
ENO Post-Hearing Brief at 131.
837

169

 exposed to adverse environmental effects 840 and that the EPA defines “fair treatment” as
meaning that “no group of people should bear a disproportionate share of the negative
environmental consequences resulting from industrial, governmental, and commercial operations
or policies." 841 ENO states that the EPA has provided the following indicators of “meaningful
involvement:” (1) “[p]eople have an opportunity to participate in decisions about activities that
may affect their environment and/or health;” (2) “[t]he public’s contribution can influence the
regulatory agency’s decision;” (3) “[c]ommunity concerns will be considered in the decision
making process;” and (4) “[d]ecision makers will seek out and facilitate the involvement of those
potentially affected;” 842 and
WHEREAS, ENO argues that with respect to Dr. Wright’s criticism that “nearby
residential neighborhoods” will be impacted, that Dr. Wright testified that there was a distance of
0.75 miles between NOPS and nearby residential neighborhoods, however, Ms. Higgins used the
EPA tool EJSCREEN to refute Dr. Wright’s claim and show that “census data indicate that no
people live within a one mile radius of the center of the site.” 843 ENO also argues that its witness
Mr. Jonathan Long testified that it was “unusual” not to have residential neighborhoods at the
fence line of a power facility, which makes the Michoud site and its one-mile buffer all the more
attractive. 844 ENO argues that the Michoud site is located in a sparsely populated census tract
that does not have the “close geographic proximity to residential neighborhoods” that Dr. Wright
suggests in her testimony; and

840

ENO Post-Hearing Brief at 131; see also, ENO-2 at 8.
ENO Post-Hearing Brief at 131-132; see also, ENO-2 at 8.
842
ENO Post-Hearing Brief at 131-132. See also, ENO-2 at 8, quoting Learn About Environmental Justice, United
States Environmental Protection Agency, https://www.epa.gov/environmentaljustice/learn-about-environmentaljustice.
843
ENO Post-Hearing Brief at 132, citing Wright-1 at 12, 14; see also, ENO-2 at 11, Ex. BMH-1.
844
ENO Post-Hearing Brief at 132-133, citing Hr’g Tr. 12/18/17, 127; see also, ENO-2 at 11.
841

170

 WHEREAS, ENO argues that NOPS is not anticipated to have any adverse effects in the
area of air quality, public health, and groundwater withdrawal, and accordingly, it will not bring
negative disproportionate effects to any group of citizens in New Orleans East, but to the
contrary will bring jobs and hundreds of millions of dollars in economic benefits to the City; 845
and
WHEREAS, with respect to meaningful involvement, ENO argues that ENO and the
Council held numerous public meetings throughout the 2015 IRP process and this docket, many
in New Orleans East. 846 ENO argues that the Council has offered multiple opportunities for
public input and has provided interested parties and the public at large substantial notice and
opportunity to be heard concerning the NOPS proposal, including public outreach meetings in
each Council district and a public hearing in Council Chambers; 847 and
WHEREAS, the Council finds that ENO has successfully demonstrated a reliability need
for generation capacity in the eastern part of New Orleans and that installing capacity in the west
will not sufficiently mitigate the need; and
WHEREAS, the Council finds that there are many proven advantages to the Michoud
site, including ENO’s ownership of the site, the availability of the gas pipeline, and transmission
and distribution interconnections and administrative building facilities, ENO’s long history of
operating a plant at that site and resulting in-depth knowledge of the site, and that adding
generation at the Michoud site will beneficially support ENO’s transmission reliability; and
WHEREAS, the Council finds that Dr. Lonsonsky’s testimony regarding the impact of
groundwater usage by NOPS at the site is more persuasive than Dr. Kolker’s due to Dr.
Losonsky’s detailed and site-specific calculations; and
845

ENO Post-Hearing Brief at 131.
ENO Post-Hearing Brief at 133.
847
ENO Post-Hearing Brief at 133-134.
846

171

 WHEREAS, the Council finds that the evidence indicates that significant mitigation of
the potential for flooding at the Michoud site has occurred, in particular the HSDRRS and the
raising of the Top of Concrete level above both the FEMA guidance and the level of flooding
seen during Katrina, and the Council finds the CPRA 2017 Master Plan prediction of no flooding
at the site under the worst-case scenario to be persuasive; and
WHEREAS, the Council is not inclined to disregard the expertise of the EPA and LDEQ
with regard to air emission, as the Joint Intervenors request. The Council recognizes that those
agencies have considerable expertise regarding and regulatory authority over air emissions. The
Council also does not believe it has a sufficient record before it in this case to create a new
regulatory standard regarding air emissions and to determine to which entities in New Orleans
such a standard should be applied. The Council, therefore, finds that it will be sufficient to
condition its approval of the plant upon ENO demonstrating compliance with all EPA and LDEQ
regulations and requirements; and
WHEREAS, in light of the requirement the Council will impose to meet all EPA and
LDEQ regulations and requirements, the Council finds that there is no potential for a
disproportionate adverse impact on minority neighborhoods in New Orleans East. The Council
also makes note of the substantial economic benefits that the project will bring to New Orleans,
from which the New Orleans East residents will benefit; and
WHEREAS, the Council has already determined above that there has been sufficient
opportunity for public input into its consideration of the NOPS application; and
WHEREAS, the Council agrees that the North Baton Rouge case supports a finding that
there is no perpetuation of racial injustice where a new plant is sited on the location of a prior
plant that had higher emissions than the new plant; and

172

 WHEREAS, the Council finds that siting the NOPS plant at Michoud is reasonable; and
IV.

Whether ENO’s proposed costs, cost recovery mechanism and Monitoring
Plan are just and reasonable and should be approved by the Council

WHEREAS, ENO has requested approval of a contemporaneous exact cost recovery
rider, to begin on the date that NOPS begins commercial operation (“COD”), to recover non-fuel
and capacity costs. The rider they propose would be similar to the PPCACR Rider that has been
used to recover costs associated with the UPS acquisition and the Ninemile 6 PPA.

The

PPCACR Rider would be an interim measure until the next full rate case or an annual Formula
Rate Plan (“FRP”) review; and
WHEREAS, ENO has also requested that major maintenance costs associated with the
project be recovered through a fuel surcharge; and
WHEREAS, ENO assumes that the 2018 Combined Rate Case will be completed before
the NOPS COD, and therefore the project costs would not normally be reflected in base rates at
that time; and
WHEREAS, ENO asserts that an exact cost recovery rider applicable to all customers is
needed, beginning on the NOPS COD, including a return on equity (“ROE”) to be determined in
the Combined Rate Case and based on ENO’s actual capital structure at the COD, and would
provide the greatest flexibility in meeting the objectives of providing ENO a reasonable
opportunity to recover its investment and resolves any timing issues that may result in regulatory
lag, while avoiding the burden and inefficiency of pancaked rate cases. 848 ENO notes that this is
the first investment of this kind that it has made in over 40 years, and says it must have a
reasonable opportunity to recover its full investment, including its authorized return; 849 and

848
849

ENO Post-Hearing Brief at 145-147.
ENO Post-Hearing Brief at 145.

173

 WHEREAS, ENO assumes that an FRP will be approved to commence in 2020
subsequent to the Combined Rate Case. ENO anticipates that its initial year ROE evaluation
would exclude the project costs and revenue recovered in its proposed rider. ENO proposes that
the rider would apply until realignment in the 2021 FRP; and
WHEREAS, ENO asserts that if it is not allowed to begin recovering project costs as of
the COD, there would be significant adverse effects on ENO’s financial condition. 850 ENO
argues that for it to undertake the construction of the first new generation in the City in over forty
years, the Company must have assurances of a reasonable opportunity for the timely recovery of
its investment and it’s allowed return on investment. 851 If there is no timely recovery, ENO will
not begin to recover operation and maintenance (“O&M”) expenses, which it will begin to incur
as of the NOPS COD, nor will it begin to recover any depreciation or ROE, until the next rate
change in the FRP, or until the next rate case, if there is no FRP; 852 and
WHEREAS, the Advisors and all Intervenors urge the Council to reject ENO’s proposed
exact cost recovery rider as inconsistent with principles of cost causation, constituting singleissue ratemaking, 853 and unnecessary. 854 NOCS and Air Products strongly object to ENO’s
proposed exact cost recovery rider because this mechanism has caused fixed costs to be borne
disproportionately by large commercial and industrial customers in the past, and would similarly
burden them unduly, particularly if NOPS costs are allocated on the kWh basis proposed by
ENO; 855 and

850

Rice-4 at 22:22-23:4; Supplemental and Amending Direct Testimony and Exhibits of Orlando Todd, Docket No.
UD-16-02, at 7:15-8:2 (July 6, 2017) (“Todd-3”).
851
Rice-4 at 23:4-8.
852
Todd-3 at 7:18-8:2.
853
Advisors’ Post-Hearing Brief at 129; NOCS Post-Hearing Brief at 26-28, Air Products Post-Hearing at 3-4, 1618; Joint Intervenors’ Post-Hearing Brief at 104.
854
NOCS Post-Hearing Brief at 26-28, 33-34, Joint Intervenors’ Post-Hearing Brief at 104, Advisors’ Post-Hearing
Brief at 129.
855
NOCS Post-Hearing Brief at 35; Air Products Post-Hearing Brief at 4.

174

 WHEREAS, Intervenor Air Products argues that ENO’s proposed exact cost recovery
rider is arbitrary because it is “outside mainstream of cost recovery practice.” 856 The proposed
mechanism, like the PPCACR Rider, would allocate the non-fuel revenue requirement to
customers on the basis of kWhs purchased. It is not “cost-based” and is “not an appropriate
means of collecting non-fuel revenue requirement;” 857 and
WHEREAS, Air Products explains that the PPCACR Rider was created as a temporary
recovery mechanism of the non-fuel revenue requirement, on a kWh basis, associated with the
Ninemile 6 PPA.

It was intended to remain in place only until the rate case that was

contemplated in the Ninemile 6 proceeding brought the costs into rate base. However, as part of
the Algiers transaction, the rate case was deferred until 2018.

Subsequently, the Council

approved continued use of the PPCACR Rider in connection with costs of the UPS acquisition.
Again, Air Products argues, the costs are allocated equally among customer classes on a kWh
basis rather than on a cost-based basis; 858 and
WHEREAS, Air Products points out that under the existing PPCACR Rider, it is paying
approximately $1.5 million too much each year from Ninemile 6 and UPS. 859 If a PPCACR
Rider were used to allocate the non-fuel revenue requirement for NOPS, Air Products would be
allocated approximately $1.06 million instead of the $400,000 it would be allocated if the 1.2%
base rate allocation factor were used instead. 860 Air Products asks the Council to realign the
existing cost recovery rider across customer classes as an equal percent of base rate revenues

856
Direct Testimony and Exhibits of Maurice Brubaker, Docket No. UD-16-02, at 4:5-7 (Jan. 6, 2017) (“Brubaker1”); Brubaker-2 at 4:8-11, 11:19-22.
857
Brubaker-1 at 4:7.
858
Brubaker-2 at 11:10-18.
859
Brubaker-2 at 4:8-15; 13:11-17.
860
Brubaker-2 at 14:4-8.

175

 within 60 days of its resolution in this proceeding, or otherwise direct ENO in the Combined
Rate Case to compensate Air Products for overcharges; 861 and
WHEREAS, the Advisors state that a utility’s revenue requirement should be based on
the utility’s overall costs, and all cost recovery rate mechanisms should derive from that basis.
Designing rates from a separate or singular cost analysis may not include the overall impacts
considered in a utility’s total revenue requirement by not reflecting offsetting changes from other
areas of the utility’s operations. While in any given year a utility may over- or under-recover its
revenue requirement for a number of reasons, 862 prolonged implementation of the type of rider
ENO proposes exacerbates the risk that costs and cost recovery are not properly allocated to
those responsible for or benefiting from the cost; and
WHEREAS, all Intervenors agree that the fixed costs of NOPS should be evaluated
together with all of ENO’s costs, and recovered on a going-forward basis through ENO’s base
rates, as set in the Combined Rate Case; 863 and
WHEREAS, ENO and the Advisors are in agreement that ENO should have a full and
fair opportunity to recover prudently incurred costs that are approved by the Council; but
reasonable opportunity to recover investment and a fair return is not a guarantee of dollar-fordollar cost recovery; 864 and
WHEREAS, the Advisors explain that the Combined Rate Case is expected to conclude
by mid-year 2019, and NOPS cost recovery can be accommodated through rates based on proformed costs in the Combined Rate Case test period. The targeted COD would be relatively

861

Air Products Post-Hearing Brief at 11.
Hr’g Tr. 12/20/17, 60:16-20.
863
NOCS Post-Hearing Brief at 26-28, Joint Intervenors’ Post-Hearing Brief at 104, Air Products Post-Hearing
Brief at 3-4.
864
Hr’g Tr. 12/20/17, 60:6-15.
862

176

 close to the effective date of revised rates from the Combined Rate Case and the subsequent
annual revenue adjustments; 865 and
WHEREAS, the Advisors support recovery of project fixed costs through the two-step
rate case mechanism proposed by Advisors’ witness Victor Prep:
If an FRP is approved by the Council, the first step would occur
with new rates anticipated to be effective by August 1, 2019. The
second step would occur with the COD of the NOPS project,
which is anticipated to be no sooner than 2020. Depending on the
structure of an approved FRP, the FRP would be filed by May 31,
2020, and an adjustment to base rate revenue (including the two
step increase, depending on the timing of a COD in 2020) could
occur in October 2020. The first FRP adjustment would be based
on a 2019 test year and customer class allocations from the
Combined Rate Case including pro-forma costs of the NOPS
project.
If an FRP is not approved, the second step increase would still
occur with the COD of the NOPS project. The stand-alone full
decoupling adjustment would be filed annually by May 31, 2020,
maintaining the total utility fixed cost revenue requirement
approved in the Combined Rate Case with the limited exception
that the revenue requirement be reset with a substantial change to
the fixed cost of service, such as the addition of new generating
capacity (NOPS).
In either of the FRP and stand-alone decoupling cases, the two step
rate increase would apply with the project COD, and there would
be three years of revenue adjustments based on the project fixed
costs updated in each test period. 866
Thus, the Advisors do not agree that exact cost recovery is required; and
WHEREAS, ENO agrees that Mr. Prep’s proposed two-step recovery method could be
reasonable, as long as ENO is assured that the recovery of the NOPS revenue requirement will
commence with the COD; 867 and

865

Advisors' Post-Hearing Brief at 130.
Prep-1 at 22:7-23:5.
867
ENO Post-Hearing Brief at 151-152. See also, Hr’g Tr. 12/19/17, 130:16-23; Hr’g Tr. 12/19/17, 130:24-131:1,
132:1-4; Hr’g Tr. 12/20/17, 50:2-20.
866

177

 WHEREAS, ENO’s witnesses also agree that the kilowatt basis used by the current
PPCACR Rider is not appropriate for NOPS investment recovery. 868 In allocating project nonfuel/fixed costs to customer classes, a demand cost allocation methodology is much more
appropriate than a kWh-based allocation. 869

If Advisors’ witness Prep’s cost recovery

mechanism is used, non-fuel O&M costs and investment would not be based on a per-kWh
basis; 870 and
WHEREAS, Air Products supports the two-step rate increase proposed by the Advisors’
witnesses that would be developed in conjunction with the 2018 Combined Rate Case. 871
Further, Air Products says that if a rider is approved, non-fuel costs should be allocated on a
contribution to base revenues basis and not on a kWh basis. 872 Air Products also suggests that
the non-fuel cost could be capitalized and deferred for consideration in a subsequent rate case or
annual review as part of an FRP; 873 and
WHEREAS, ENO asserts that if its proposed rider is implemented in the context of an
FRP, it would not violate principles of single-issue ratemaking. To the extent that the Council
disagrees with its view, ENO asserts that the circumstances warrant an exception to the general
prohibition on single-issue ratemaking; 874 and
WHEREAS, NOCS contends that if an FRP is established in the Combined Rate Case,
the fixed, non-fuel costs of NOPS should be collected inside (and subject to) the earnings
bandwidth; 875 and

868

Hr’g Tr. 12/19/17, 131:18-25. Hr’g Tr. 12/20/17, 49:5-50:8; 57:17-58:6.
Hr’g Tr. 12/19/17, 134:18-135:7. Hr’g Tr. 12/20/17, 49:5-50:8; 57:17-58:6.
870
Hr’g Tr. 12/19/17, 134:12-16.
871
Air Products Post-Hearing Brief at 3-4.
872
Air Products Post-Hearing Brief at 3-4.
873
Brubaker-2 at 4:16-21; 14:12-17.
874
ENO Post-Hearing Brief 148-149.
875
NOCS Post-Hearing Brief at 35-36.
869

178

 WHEREAS, Advisors’ witness Prep argues further that if the Council does not establish
an FRP in the Combined Rate Case, an evaluation of NOPS cost recovery and related revenue
adjustment can occur with a decoupling mechanism consistent with the Council’s guidance in
Resolution No. R-16-103; 876 and
WHEREAS, the Council agrees that a utility’s revenue requirement should be based on
the utility’s overall costs, and all cost recovery rate mechanisms should derive from that basis.
Departure from this general ratemaking principle should occur only under limited circumstances
where it has been conclusively shown that failure to allow contemporaneous exact cost recovery
would have a severe adverse impact on the utility; and
WHEREAS, ENO has not demonstrated that its financial stability and credit ratings
would be adversely affected if the opportunity for cost recovery were provided by means other
than a contemporaneous exact cost recovery rider. ENO has only provided general statements,
without any credible analysis, that “prolonged regulatory lag on recovery of a substantial
investment like NOPS could severely limit the Company’s ability to make other required
investments and respond to emergency conditions;” 877 and
WHEREAS, based on the evidence in the record, and given that even ENO’s own
witnesses have conceded that the PPCACR Rider mechanism, as proposed, is not an appropriate
cost recovery mechanism for NOPS, the Council does not believe that recovery of project fixed
costs should occur through a rider as proposed by ENO. Instead, base rate revenues should be
used to develop a current estimate of the project fixed costs allocated to customer classes, with
the final allocation methodology to be determined in the Combined Rate Case. In the event that
the COD is later than the test periods and effective dates of the Combined Rate Case rates, the

876
877

Resolution No. R-16-103 (Apr. 7, 2016).
Rice-4 at 22:19-23:8.

179

 recovery of project fixed costs should be accomplished using the two-step increase or adjustment
to base rates that Advisors’ witness Mr. Prep has set forth; and
WHEREAS, the Council finds that the request by Air Products for the Council to realign
ENO’s revenue recovery under the current PPCACR Rider within 60 days of issuing an order on
ENO’s NOPS proposal is beyond the scope of this proceeding. The PPCACR Rider associated
with the Ninemile 6 PPA and UPS acquisition were addressed in Docket Nos. UD-11-03 and
UD-15-01. Air Products did not intervene in those proceedings and the Council is not persuaded
that they should be reopened as part of its decision on ENO’s NOPS proposal in this proceeding.
The current PPCACR Rider will be evaluated in the Combined Rate Case, along with all of
ENO’s costs, including project fixed costs of NOPS; and
LTSA cost recovery
WHEREAS, ENO is contemplating entering a long term service agreement (“LTSA”)
with the original equipment manufacturer for major maintenance for either NOPS alternative.
ENO says it has a term sheet with the original equipment manufacturer for the CT 878 and is
exploring whether an LTSA is possible for the RICE Alternative. 879 The LTSA for the CT
would include planned and unplanned maintenance (subject to cost ceilings), remote monitoring
and diagnostics, combustion system tuning services, and an on-site technical advisor. The
manufacturer would be required to maintain the reliability, output and efficiency of the unit, as
well as NOx and CO emissions and turbine vibration. It also would limit the duration of
scheduled outages; 880 and

878
Direct Testimony and Exhibits of Robert A. Breedlove, Docket No. UD-16-02, at 7:9-21 (June 20, 2016)
(“Breedlove-1”).
879
Supplemental and Amending Direct Testimony and Exhibits of Robert A. Breedlove, Docket No. UD-16-02, at
2:19-20 (July 6, 2017) (“Breedlove-3”); Todd-3 at 4:6-8; 8:19-20.
880
Breedlove-1 at 8:5-12.

180

 WHEREAS, ENO says that maintenance costs on a non-variable or transactional basis
would be recovered in base rates, 881 however if an LTSA is executed before the COD, ENO
requests authorization to recover the LTSA expenses through the fuel adjustment clause
(“FAC”). 882 ENO asserts that use of the FAC for recovery of LTSA costs is appropriate because
(1) the expenses are variable to the extent that major maintenance (and related payments) is
based on utilization, including unit starts and run-time of the facility, and (2) customers pay
actual LTSA costs when incurred. 883 ENO says that recovery through base rates runs a risk that
ENO will recover more or less than the actual costs incurred; 884 and
WHEREAS, ENO states that LTSA expenses associated with Ninemile 6 and UPS are
recovered through the FAC, but such recovery is non-precedential, therefore ENO must receive
Council authorization in order to include NOPS LTSA expenses in the FAC; 885 and
WHEREAS, ENO notes that recovery of MISO market settlement revenues and
expenses associated with either NOPS Alternative would occur through the FAC, as currentlyapproved, except that administrative expenses and revenues would be recovered through ENO’s
MISO Cost Recovery Rider; 886 and
WHEREAS, the Advisors recommend against ENO’s requested approach for recovery
of LTSA costs. The LTSA costs are primarily fixed costs similar to traditional project fixed
maintenance costs, and should be recovered through base rates using appropriate cost allocations,

881

Direct Testimony and Exhibits of Orlando Todd, Docket No. UD-16-02, at 11:7-12 (June 20, 2016) (“Todd-1”);
Todd-3 at 9:13-15.
882
Todd-1 at 10:8-17; Todd-3 at 8:20-23.
883
Todd-1 at 10:12-17; Todd-3 at 8:23-9:8; ENO Post-Hearing Brief at 153-154.
884
Todd-1 at 10:12-17; Todd-3 at 8:23-9:8.
885
Todd-1 at 10:21-11:2.
886
Todd-1 at 11:16-21; Todd-3 at 9:20-10:3.

181

 rather than through the FAC as proposed by ENO. LTSA costs can vary somewhat, however,
they do not tend to fluctuate widely to the extent that fuel costs do; 887 and
WHEREAS, the Advisors argue, and ENO concedes, that not all variable costs go into
the FAC. 888 The primary purpose of the FAC is to recover fuel costs. 889 The LTSA does not
directly include any fuel costs; 890 and
WHEREAS, Advisors’ witness Mr. Prep reviewed treatment of LTSA costs in other
retail jurisdictions and found that the general consensus among regulatory bodies is to recover
LTSA costs in base rates. 891 ENO witness Ms. Lovorn-Marriage noted that the LPSC has
allowed recovery of LTSA costs associated with combined cycle units through ELL’s FAC. 892
However, the record contains no details on the details of those approvals; and
WHEREAS, the Advisors assert that allowing ENO to recover its LTSA maintenance
costs for NOPS through the FAC rider would include more fixed costs in ENO’s FAC at a time
when the Council should be considering in the Combined Rate Case the elimination of such
occurrences in the interest of an equitable cost allocation among the rate classes. The FAC was
originally designed to flow variable costs such as fuel through to ratepayers on a per-kWh of
usage basis. Continued loading in the FAC of fixed costs that do not vary with kWh use is
contrary to this intent and results in improper allocation of those costs. LTSA costs are expected
to be regularly occurring and predictable. 893 As such, ENO should be allowed to recover any

887

Prep-1 at 24:9-25:5; Hr’g Tr. 12/19/17, 141:18-23.
Hr’g Tr. 12/19/17, 10-23; 142:9-14, 143:1-13.
889
Hr’g Tr 12/19/17, 140:25-141:3.
890
Hr’g Tr. 12/19/17, 145:14-18.
891
Prep-1 at 25:8-14.
892
Rebuttal Testimony and Exhibits of Shauna Lovorn-Marriage, Docket No. UD-16-02, at 7:12-17 (Nov. 30, 2017)
(“Lovorn-2”).
893
Advisors’ Post-Hearing Brief at 135; Prep-1 at 24:9-11.
888

182

 prudently incurred LTSA costs through the same cost recovery mechanism that the Council
ultimately approves for all other NOPS fixed/non-fuel costs; 894 and
WHEREAS, NOCS agrees with Advisors that the LTSA costs are fixed and predictable
and should not be recovered through the FAC; 895 and
WHEREAS, the Council is not persuaded that ENO has demonstrated that LTSA costs
are appropriate for inclusion in the FAC, as opposed to recovery through base rates. First, based
on the record, the execution of an LTSA is speculative at this point. Second, there is no evidence
that anticipated LTSA costs would fluctuate widely or be so unpredictable as to warrant that they
be treated separately from other O&M costs associated with the project.

LTSA costs are

primarily fixed costs similar to traditional project fixed maintenance costs, and should be
recovered through base rates using appropriate cost allocations, rather than through the FAC as
proposed by ENO; and
Rate Impact
WHEREAS, ENO estimates the typical monthly bill impacts of the two proposed NOPS
units as follows:

Residential (1000 kWh)
Commercial (9,125
kWh)
Industrial (91,250 kWh)

RICE Alternative
$7.19
$65.62

CT Alternative
$5.61
$51.16

$656.19

$511.57

WHEREAS, Advisors’ witness Mr. Watson explains that in estimating typical monthly
bill impacts, ENO first calculated an incremental supply cost by case and by year (i.e., an
incremental revenue requirement impact). ENO then levelized and unitized these incremental
supply costs by calculating their present value (PV) across 17 years and then dividing that PV
894
895

Prep-1 at 24:11-25:2.
NOCS Post-Hearing Brief at 37.

183

 value by the PV of forecasted MWh sales across the same timeframe, resulting in a levelized
$/kWh bill impact for each case (a single $/kWh value for all rate classes similar to the per-kWh
cost allocation methodology in the existing PPCACR Rider). ENO then multiplies its levelized
$/kWh bill impact by a typical monthly consumption by rate class to present a levelized $/mo
typical bill impact; 896 and
WHEREAS, Advisors’ witness Mr. Watson disagreed with ENO’s methodology and
instead estimated the monthly bill impact based on an allocation of fixed costs among the rate
classes (based on 2016 base-rate revenues), and an allocation of variable costs based on kWh
consumption (i.e., using the cost recovery method suggested by Advisors’ witness Mr. Prep).897
Advisors’ witness Watson then estimated typical monthly bill impacts under several scenarios as
follows; 898 and
Typical Monthly Bill Impact
(Reflects a MISO PRA MCP of $6.00/kW-year and an ROE of 9.75%)
Residential
Commercial
Typical Bill
Typical Bill
Industrial Typical Bill
Impact
Impact
Impact
Case
(1,000 kWh/mo) (9,125 kWh/mo)
(91,250 kWh/mo)
Cases w/o Additional DSM Measures
RICE Alternative
$6.43
$44.87
$333.84
CT Alternative
$6.79
$47.75
$360.26
Cases w/ the Council’s 2% DSM Goal
RICE Alternative
$22.41
$160.13
$1,170.70
CT Alternative
$22.81
$163.31
$1,199.08

896

Watson-1 at 13:7-14:2.
Watson-1 at 14:14-16.
898
Watson-1 at 15:2.
897

184

 WHEREAS, the DSM bill impacts were modeled using the costs of achieving the
Council’s 2% DSM Goal as estimated by Navigant in its June 2017 DSM Potential Study; 899 and
WHEREAS, ENO disagrees with the Advisors’ billing impact estimates. According to
ENO witness Mr. Cureington, the Council’s 2% DSM Goal is unachievable and unsustainable
over the long-term planning horizon. He also says that the assumed MISO PRA clearing prices
will not remain constant over the planning horizon. He says that the Advisors’ assumptions are
not reasonable, and therefore the Advisors’ estimated bill impacts are not reasonable; 900 and
WHEREAS, ENO’s estimate uses an assumed ROE of 11.04%, while Advisors’ witness
Mr. Watson used an ROE of 9.75% in his estimates. 901 Employing a 9.75% ROE as compared to
the 11.04% ROE reduces the rate impact estimates; 902 and
WHEREAS, the Advisors do not advocate any specific ROE at this time. 903 They assert
it should be evaluated as part of the Combined Rate Case. However, the Advisors note that 9.75%
is in line with ROEs recently set by retail regulators; 904 and
WHEREAS, Joint Intervenors agree with the Advisors that the proposed ROE should be
evaluated as part of the rate case. They argue that ENO’s assumed 11% ROE is too high and
would likely result in a windfall to ENO; 905 and
WHEREAS, the Advisors recommend that the Council use their billing impact estimates
to assess potential the potential impact of NOPS on customers. 906 Apart from the disagreement
regarding achievability of the Council’s 2% DSM Goal or the impact of MISO market prices,

899

Watson-1 at 15:6-8.
Cureington-7 at 8:5‒11.
901
Watson-1 at 19:14-15.
902
Watson-1 at 21:3-8.903 Watson-1 at 17:14-18:8; 18:12; 19:3.
903
Watson-1 at 17:14-18:8; 18:12; 19:3.
904
Watson-1 at 17:1-13; 18:12-16.
905
Joint Intervenors’ Post-Hearing Brief at 104.
906
Advisors’ Post-Hearing Brief at 139.
900

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 ENO’s assumed higher ROE has the effect of pushing up the cost estimates, which in turn affects
the rate impact estimates; 907 and
WHEREAS, Joint Intervenors also ask the Council to take steps to mitigate any financial
risk to ratepayers associated with the MISO capacity markets or with construction cost
overruns. 908 They ask the Council to condition any approval of NOPS (1) by requiring ENO to
bear the shortfall in actual capacity market sales revenue compared to their expected sales level,
which Joint Intervenors believe is too optimistic; and (2) by imposing a construction-costs
recovery cap at the projected costs amounts set forth in ENO’s application. Specifically, Joint
Intervenors request that ENO be required to bear the costs if the MISO capacity market does not
reach at least 60% of the CONE by 2022 and remain at or above that level throughout the
planning horizon. The 60% of CONE price, Joint Intervenors argue, is the lowest capacity
market auction price ENO agreed to study. 909 And with respect to construction costs, Joint
Intervenors urge the Council to disallow recovery of costs beyond ENO’s contingency budget
(which is based on a 50% confidence interval), or to require ENO to submit revised cost
estimates using a 95% confidence interval for the contingency budget; 910 and
WHEREAS, the Council finds the Advisors’ bill impact calculations to be based on
more reasonable assumptions and therefore to be more convincing than ENO’s rate impact
calculations and notes that the Advisors' bill impact calculations show the RICE Alternative to
have a slightly lower impact on customer bills than the CT Alternative; and
WHEREAS, the Council notes that the request by the Joint Intervenors that the Council
condition any approval of NOPS by requiring ENO to bear the cost of any shortfall in actual
907

Advisors’ Post-Hearing Brief at 139.
Joint Intervenors’ Post-Hearing Brief at 104-105.
909
Joint Intervenors’ Post-Hearing Brief at 105, citing Cureington-6, Ex. SEC-12 at 8; Hr’g Tr., 12/18/17, 203:19204:23.
910
Joint Intervenors’ Post-Hearing Brief at 105.
908

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 capacity market sales revenue from the gas plant if the MISO capacity market does not reach at
least 60% of CONE by 2022 and to impose a construction-costs recovery cap at the presently
quoted amounts in ENO’s application, preventing ENO’s recovery of construction costs beyond
the level of ENO’s contingency budget was made for the first time in the Joint Intervenors’ PostHearing Brief, and therefore no other party, including ENO, has had opportunity to respond to
this request in any way; and
WHEREAS, the Council also notes that it is obligated to set rates at a just and
reasonable level, which includes the obligation to allow the utility an opportunity to recover its
prudently incurred costs and a reasonable rate of return on its investment. 911 The Council finds,
however, that there is no evidence in the record that the conditions requested by the Joint
Intervenors will result in a just and reasonable rate that is fair to ratepayers and allows the utility
to recover its prudently incurred costs and a reasonable rate of return on its investment. The
Council, therefore, will deny the Joint Intervenors’ request; and
WHEREAS, as is discussed above, the Council will evaluate ENO’s cost recovery
related to the NOPS project in the Combined Rate Case; and
Monitoring Plan
WHEREAS, ENO proposes reporting to the Council quarterly on the status of NOPS and
provided a proposed monitoring plan; 912 and
WHEREAS, Advisors’ witness Mr. Rogers generally agrees with the proposed
monitoring plan, but recommends that the Council build in the ability to modify the reporting to
the extent that it desires additional information and such information is available and does not

911

See Bluefield Water Works & Improvement Co. v. W. Va. Pub. Serv. Comm’n, 262 U.S. 679 (1923); see also
Federal Power Comm’n v. Hope Natural Gas Co., 320 U.S. 591 (1944). See also, Prep-1 at 12:11-14.
912
Rogers-1 at 3:16-18, 49:13-19.

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 place an undue burden on ENO. 913 The Advisors note that quarterly reports typically provide
only summary-level information, and suggest that the Council will want to fully understand
developments, particularly if there are changes in costs or project schedule; 914 and
WHEREAS, ENO states that its monitoring plan is essentially uncontested and
reasonable, and agrees to the Advisors’ proposed modifications to its plan; 915 and
WHEREAS, Air Products states that it supports the position of the Advisors on the
monitoring plan; 916 and
WHEREAS, the Council agrees that it may at some point wish to have additional
information. Because ENO has agreed to Mr. Rogers’ proposed modifications, the Council will
accept the proposed monitoring plan as modified, and believes that monitoring and reporting
requirements as modified by Advisors’ witness Rogers are appropriate; and
WHEREAS, the omission from this decision of any argument or portion of the record
that may exist or may have been raised by the participants in their briefs does not mean that it
has not been considered. All such arguments and portions of the record have been evaluated and
found to add nothing further to the substance or effect of this decision; now therefore:
BE IT RESOLVED BY THE COUNCIL OF THE CITY OF NEW ORLEANS
THAT:
1. The Council finds that the NOPS RICE Alternative serves the public convenience and
necessity and is in the public interest, and therefore prudent.
2. ENO shall have a full and fair opportunity to recover all prudently incurred costs
associated with the RICE Alternative.
3. The cost recovery of the NOPS project fixed costs shall be evaluated during the
Council’s consideration of the Combined Rate Case to be filed in 2018, and cost
recovery shall be accommodated through a two-step rate adjustment as recommended
913

Rogers-1 at 49:8-12.
Advisors’ Post-Hearing Brief at 139.
915
ENO Post-Hearing Brief at 154.
916
Air Products Post-Hearing Brief at 4.
914

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 by the Advisors. After the Council’s complete vetting of the revenue requirement
impacts of the NOPS project relative to total ENO operations in the Combined Rate
Case, the Council will decide on the timing of any step rate adjustments to reflect
NOPS cost recovery that may be appropriate to correlate with NOPS date of
commercial operation. If the Council does not establish an FRP in the Combined
Rate Case, an evaluation of NOPS cost recovery and related revenue adjustment
could occur with a decoupling mechanism consistent with the Council’s guidance in
Resolution No. R-16-103, to the extent that such a decoupling mechanism is approved
in the Combined Rate Case.
4. Any costs associated with an LTSA should be recovered through base rates using
appropriate cost allocations as determined in the Combined Rate Case.
5. ENO’s proposed monitoring plan is approved, with an additional provision to be
added: that the reporting requirement may be adjusted at the request of the Advisors
unless ENO can demonstrate that such a request would create an undue burden on
ENO.
6. ENO is required to demonstrate its compliance with all applicable laws and
regulations by filing with the Council all permits granted, and orders or rulings issued
by any local, state or federal agency with jurisdiction over the project, including, but
not limited to the EPA and LDEQ.
THE FOREGOING RESOLUTION WAS READ IN FULL, THE ROLL WAS
CALLED ON THE ADOPTION THEREOF AND RESULTED AS FOLLOWS:
YEAS:
NAYS:
ABSENT:
AND THE RESOLUTION WAS ADOPTED.

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